SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2007
FOR THE TRANSITION PERIOD FROM ___________ TO _____________.
Commission file number: 000-25170
AURORA OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)
Utah | 87-0306609 | |
(State or other Jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
4110 Copper Ridge Dr, Suite 100 Traverse City, Michigan 49684 | |
(Address of principal executive offices) | |
(231) 941-0073 | |
(Registrant’s telephone number, including area code) |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.
Indicate by check mark whether the registrant is a shell company (as defined in rule 12b-2 of the Exchange Act).
The number of shares of the registrant’s common stock outstanding as of April 30, 2007, was 101,644,456.
FORM 10-Q
INDEX
PART I | FINANCIAL INFORMATION | 1 |
Item 1. | Condensed Consolidated Financial Statements | 2 |
Condensed Consolidated Balance Sheets as of March 31, 2007 (Unaudited), and December 31, 2006 | 2-3 | |
Unaudited Statements of Operations for the Three Months Ended March 31, 2007, and 2006 | 4 | |
Unaudited Statements of Shareholders’ Equity for the Three Months Ended March 31, 2007, and 2006 | 5 | |
Unaudited Statements of Cash Flows for the Three Months Ended March 31, 2007, and 2006 | 6 | |
Notes to Unaudited Condensed Consolidated Financial Statements | 7 | |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 18 |
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 25 |
Item 4. | Controls and Procedures | 26 |
PART II | OTHER INFORMATION | 27 |
Item 1. | Legal Proceedings | 27 |
Item 1A. | Risk Factors | 27 |
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 27 |
Item 3. | Defaults Upon Senior Securities | 27 |
Item 4. | Submission of Matters to a Vote of Security Holders | 27 |
Item 5. | Other Information | 27 |
Item 6. | Exhibits | 28 |
Signatures | 29 |
i
PART I
Cautionary Note Regarding Forward-Looking Statements
This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts are forward-looking statements. You can find many of these statements by looking for words such as “believes,” “expects,” “anticipates,” “estimates,” “intends,” or similar expressions used in this report.
These forward-looking statements are subject to numerous assumptions, risks, and uncertainties. Factors which may cause our actual results, performance, or achievements to be materially different from any future results, performance, or achievements expressed or implied by us in those statements include, among others, the following:
· | the quality of our properties with regard to, among other things, the existence of reserves in economic quantities; |
· | uncertainties about the estimates of reserves; |
· | our ability to increase our production and oil and natural gas income through exploration and development; |
· | the number of well locations to be drilled and the time frame within which they will be drilled; |
· | the timing and extent of changes in commodity prices for natural gas and crude oil; |
· | domestic demand for oil and natural gas; |
· | drilling and operating risks; |
· | the availability of equipment, such as drilling rigs and transportation pipelines; |
· | changes in our drilling plans and related budgets; and |
· | the adequacy of our capital resources and liquidity, including, but not limited to, access to additional borrowing capacity. |
Because such statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. You are cautioned not to place undue reliance on such statements, which speak only as of the date of this report.
Certain Definitions
As used in this report, “mcf” means thousand cubic feet, “mmcf” means million cubic feet, “bcf” means billion cubic feet, “bbl” means barrel, “mbbls” means thousand barrels, and “mmbbls” means million barrels. Also in this report, “boe” means barrel of oil equivalent, “mcfe” means thousand cubic feet of natural gas equivalent, “mmcfe” means million cubic feet of natural gas equivalent, “mmbtu” means million British thermal units, and “bcfe” means billion cubic feet of natural gas equivalent. Natural gas equivalents and crude oil equivalents are determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate, or natural gas liquids. All estimates of reserves and information related to production contained in this report, unless otherwise noted, are reported on a “net” basis.
1
ITEM 1. | CONDENSED CONSOLIDATED FINANCIAL STATEMENTS |
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
March 31, 2007 (Unaudited) | December 31, 2006 (Audited) | ||||||
ASSETS | |||||||
CURRENT ASSETS: | |||||||
Cash and cash equivalents | $ | 2,149,766 | $ | 1,735,396 | |||
Accounts receivable | |||||||
Oil and natural gas sales | 4,237,085 | 4,082,231 | |||||
Joint interest owners | 2,063,226 | 3,079,715 | |||||
Notes receivable | 221,788 | 341,698 | |||||
Drilling advances | 506,113 | 1,408,860 | |||||
Prepaid expenses and other current assets | 933,072 | 264,024 | |||||
Short-term derivative instruments | 670,750 | 3,552,060 | |||||
Total current assets | 10,781,800 | 14,463,984 | |||||
PROPERTY AND EQUIPMENT: | |||||||
Oil and natural gas properties, using full cost accounting: | |||||||
Proved properties | 131,601,056 | 121,178,499 | |||||
Unproved properties | 46,697,332 | 41,847,526 | |||||
Properties held for sale | 5,488,140 | 8,896,568 | |||||
Less: accumulated depletion and amortization | (11,375,302 | ) | (10,628,438 | ) | |||
Total oil and natural gas properties, net | 172,411,226 | 161,294,155 | |||||
Pipelines | 5,003,152 | 4,881,240 | |||||
Other property and equipment | 5,116,321 | 5,093,777 | |||||
Less: accumulated depreciation | (933,918 | ) | (753,789 | ) | |||
Total property and equipment, net | 181,596,781 | 170,515,383 | |||||
OTHER ASSETS: | |||||||
Long-term derivative instruments | 737,290 | 1,668,573 | |||||
Goodwill | 19,373,264 | 19,373,264 | |||||
Intangibles (net of accumulated amortization of $3,334,167 and $2,946,250, respectively) | 1,620,833 | 2,008,750 | |||||
Other investments | 946,305 | 985,706 | |||||
Debt issuance costs (net of accumulated amortization of $1,110,769 and $892,535, respectively) | 2,145,104 | 2,363,898 | |||||
Other | 999,193 | 1,007,634 | |||||
Total other assets | 25,821,989 | 27,407,825 | |||||
TOTAL ASSETS | $ | 218,200,570 | $ | 212,387,192 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
2
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(continued)
March 31, 2007 (Unaudited) | December 31, 2006 (Audited) | ||||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | |||||||
CURRENT LIABILITIES: | |||||||
Accounts payable and accrued liabilities | $ | 5,065,743 | $ | 5,623,591 | |||
Accrued exploration, development, and leasehold costs | 4,785,299 | 11,587,850 | |||||
Short-term bank borrowings | 8,615 | 542,788 | |||||
Current portion of obligations under capital leases | 6,427 | 8,868 | |||||
Current portion of note payable—other | 131,013 | 161,774 | |||||
Current portion of mortgage payable | 91,431 | 95,828 | |||||
Drilling advances | 206,023 | 19,383 | |||||
Total current liabilities | 10,294,551 | 18,040,082 | |||||
LONG-TERM LIABILITIES: | |||||||
Obligations under capital leases, net of current portion | 6,154 | 8,228 | |||||
Asset retirement obligation | 766,670 | 1,331,893 | |||||
Notes payable | 103,794 | 118,547 | |||||
Mortgage payable | 3,051,211 | 3,079,470 | |||||
Senior secured credit facility | 28,000,000 | 10,000,000 | |||||
Mezzanine financing | 40,000,000 | 40,000,000 | |||||
Total long-term liabilities | 71,927,829 | 54,538,138 | |||||
Total liabilities | 82,222,380 | 72,578,220 | |||||
Minority interest in net assets of subsidiaries | 91,220 | 77,873 | |||||
COMMITMENTS AND CONTINGENCIES (Note 9) | |||||||
SHAREHOLDERS’ EQUITY | |||||||
Common stock, $0.01 par value; authorized 250,000,000 shares; issued and outstanding 101,644,456 shares and 101,412,966 shares, respectively | 1,016,445 | 1,014,130 | |||||
Additional paid-in capital | 138,812,094 | 138,105,626 | |||||
Accumulated other comprehensive income | 1,408,040 | 5,220,633 | |||||
Accumulated deficit | (5,349,609 | ) | (4,609,290 | ) | |||
Total shareholders’ equity | 135,886,970 | 139,731,099 | |||||
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 218,200,570 | $ | 212,387,192 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
3
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended March 31, | |||||||
2007 | 2006 | ||||||
REVENUES: | |||||||
Oil and natural gas sales | $ | 5,929,576 | $ | 5,416,866 | |||
Pipeline transportation and marketing | 129,268 | 111,766 | |||||
Field service and sales | 189,518 | - | |||||
Interest and other | 13,513 | 55,364 | |||||
Total revenues | 6,261,875 | 5,583,996 | |||||
EXPENSES: | |||||||
Production taxes | 263,098 | 214,159 | |||||
Production and lease operating expense | 1,925,893 | 1,658,726 | |||||
Pipeline operating expense | 113,420 | 65,281 | |||||
Field services expense | 154,272 | - | |||||
General and administrative expense | 2,260,343 | 1,566,694 | |||||
Oil and natural gas depletion and amortization | 746,865 | 941,965 | |||||
Other assets depreciation and amortization | 568,606 | 467,752 | |||||
Interest expense | 981,532 | 1,594,135 | |||||
Taxes (refunds), other | (25,182 | ) | 1,667 | ||||
Total expenses | 6,988,847 | 6,510,379 | |||||
LOSS BEFORE MINORITY INTEREST | (726,972 | ) | (926,383 | ) | |||
MINORITY INTEREST IN INCOME OF SUBSIDIARIES | (13,347 | ) | (12,800 | ) | |||
NET LOSS | $ | (740,319 | ) | $ | (939,183 | ) | |
NET LOSS PER COMMON SHARE—BASIC AND DILUTED | $ | (0.01 | ) | $ | (0.01 | ) | |
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING—BASIC AND DILUTED | 101,552,888 | 70,265,281 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
4
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(Unaudited)
Three Months Ended March 31, | |||||||||||||
2007 | 2006 | ||||||||||||
COMMON STOCK: | Shares | Amount | Shares | Amount | |||||||||
Balance, beginning | 101,412,966 | $ | 1,014,130 | 61,536,261 | $ | 615,363 | |||||||
Cashless exercise of stock options and warrants | 78,158 | 782 | 3,125,105 | 31,251 | |||||||||
Conversion of redeemable convertible preferred stock to common stock | - | - | 23,334 | 233 | |||||||||
Exercise of stock options and warrants | 153,332 | 1,533 | 15,375,457 | 153,755 | |||||||||
Issuance of stock to related parties in lieu of commission relating to exercise of warrants | - | - | 1,469,860 | 14,699 | |||||||||
Balance, end | 101,644,456 | 1,016,445 | 81,530,017 | 815,301 | |||||||||
ADDITIONAL PAID-IN CAPITAL: | |||||||||||||
Balance, beginning | 138,105,626 | 58,670,698 | |||||||||||
Cashless exercise of stock options and warrants | (782 | ) | (31,251 | ) | |||||||||
Conversion of redeemable convertible preferred stock to common stock | - | 39,768 | |||||||||||
Costs of equity offerings | (10,096 | ) | - | ||||||||||
Stock-based compensation | 661,380 | 370,466 | |||||||||||
Exercise of stock options and warrants | 55,966 | 17,892,645 | |||||||||||
Issuance of stock to related party in lieu of commission relating to exercise of warrants | - | (14,699 | ) | ||||||||||
Balance, end | 138,812,094 | 76,927,627 | |||||||||||
ACCUMULATED OTHER COMPREHENSIVE INCOME: | |||||||||||||
Balance, beginning | 5,220,633 | - | |||||||||||
Changes in fair value of derivative instruments | (3,027,593 | ) | - | ||||||||||
Recognition of gain on derivative instruments | (785,000 | ) | - | ||||||||||
Balance, end | 1,408,040 | - | |||||||||||
ACCUMULATED DEFICIT: | |||||||||||||
Balance, beginning | (4,609,290 | ) | (2,660,134 | ) | |||||||||
Net loss | (740,319 | ) | (939,183 | ) | |||||||||
Balance, end | (5,349,609 | ) | (3,599,317 | ) | |||||||||
TOTAL SHAREHOLDERS’ EQUITY | $ | 135,886,970 | $ | 74,143,611 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
5
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended March 31, | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | 2007 | 2006 | |||||
Net loss | $ | (740,319 | ) | $ | (939,183 | ) | |
Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | |||||||
Depreciation, depletion, and amortization | 1,315,471 | 1,409,717 | |||||
Amortization of debt issuance costs | 218,234 | 214,976 | |||||
Accretion of asset retirement obligation | 18,895 | 15,237 | |||||
Stock-based compensation | 594,044 | 157,392 | |||||
Equity loss of other investments | 96,181 | 68,406 | |||||
Minority interest income of subsidiaries | 13,347 | 12,800 | |||||
Changes in operating assets and liabilities, net of effects of merger: | |||||||
Accounts receivable - oil and natural gas sales | (154,854 | ) | 12,343 | ||||
Accounts receivable - joint interest owners | 1,016,489 | (1,491,410 | ) | ||||
Drilling advance - assets | 902,747 | 92,880 | |||||
Drilling advance - liabilities | 186,640 | - | |||||
Prepaid expenses and other assets | (380,755 | ) | (91,283 | ) | |||
Accounts payable and accrued liabilities | (557,848 | ) | (898,635 | ) | |||
Net cash provided by (used in) operating activities | 2,528,272 | (1,436,760 | ) | ||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||
Exploration and development of oil and natural gas properties | (17,593,833 | ) | (7,904,781 | ) | |||
Leasehold expenditures, net | (2,768,746 | ) | (13,809,479 | ) | |||
Acquisition of oil and natural gas properties | - | (23,938,811 | ) | ||||
Sale of oil and natural gas properties | 1,025,000 | 6,990,681 | |||||
Acquisitions/additions for pipeline, property, and equipment | (144,456 | ) | (3,781,711 | ) | |||
Additions in other investments | - | (250,000 | ) | ||||
Other, net | (37,412 | ) | (20,986 | ) | |||
Net cash used in investing activities | (19,519,447 | ) | (42,715,087 | ) | |||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||
Net short-term bank borrowings (payments) | (534,173 | ) | (1,300,000 | ) | |||
Advances on senior secured credit facility | 18,000,000 | 35,000,000 | |||||
Payments on mortgage obligations | (32,656 | ) | (13,442 | ) | |||
Payments of financing fees on credit facilities | (25,000 | ) | (2,386,613 | ) | |||
Net proceeds from exercise of options and warrants | 57,499 | 18,046,400 | |||||
Other, net | (60,125 | ) | (2,152 | ) | |||
Net cash provided by financing activities | 17,405,545 | 49,344,193 | |||||
Net increase in cash and cash equivalents | 414,370 | 5,192,346 | |||||
Cash and cash equivalents, beginning of the period | 1,735,396 | 11,980,638 | |||||
Cash and cash equivalents, end of the period | $ | 2,149,766 | $ | 17,172,984 | |||
NONCASH FINANCING AND INVESTING ACTIVITIES: | |||||||
Oil and natural gas properties asset retirement obligation | $ | (581,840 | ) | $ | 812,634 | ||
Accrued exploration and development costs on oil and natural gas properties | 4,321,933 | 2,633,857 | |||||
Accrued leasehold costs | 463,366 | 1,053,943 | |||||
Pipeline acquisition, transfer of investment to pipeline assets | - | 1,100,973 | |||||
Oil and natural gas properties capitalized stock-based compensation | 67,336 | 213,074 | |||||
CASH PAID FOR INTEREST | $ | 1,304,765 | $ | 1,497,856 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
6
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. | ORGANIZATION AND NATURE OF BUSINESS |
Effective May 11, 2006, Cadence Resources Corporation (“Cadence”) and its wholly owned subsidiaries (collectively, the “Company”) amended its articles of incorporation to change its name to Aurora Oil & Gas Corporation (“AOG”). The Company is an oil and natural gas corporation engaged in the exploration, acquisition, development, production, and sale of natural gas and crude oil. The Company generates most of its revenue from the production and sale of natural gas. The Company is currently focused on acquiring and developing operating interests in unconventional drilling programs in the Michigan Antrim shale and the New Albany shale of Indiana and Kentucky.
The Company uses different strategies for natural gas sales depending on the location of the field and the local markets. In most cases, the Company connects to nearby high pressure transmission pipelines. The Company has six base contracts for the sale of natural gas and currently utilizes one primary marketing company for all of its operated properties. The Company sets the firm delivery volume obligation under these contracts on either a monthly or a daily basis with the amount of the obligation varying from month to month or day to day. As new wells come online and production volume increases, new production will be sold in the spot markets or under the base contracts.
The Company’s revenue, profitability, and future rate of growth are substantially dependent on prevailing prices of natural gas and oil. Historically, the energy markets have been very volatile, and it is likely that oil and natural gas prices will continue to be subject to wide fluctuations in the future. A substantial or extended decline in natural gas and oil prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows, and access to capital and on the quantities of natural gas and oil reserves that can be economically produced.
NOTE 2. | BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
Basis of Presentation
The financial information included herein is unaudited, except the balance sheet as of December 31, 2006, which has been derived from our audited consolidated financial statements as of December 31, 2006. Such information includes all adjustments (consisting solely of normal recurring adjustments), which are, in the opinion of management, necessary for a fair presentation of financial position, results of operations, and cash flows for the interim periods. The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year. Certain amounts as reported in the 2006 financial statements have been reclassified to conform with the 2007 presentation.
Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission. These condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in our Annual Report on Form 10-KSB for the year ended December 31, 2006.
Principles of Consolidation
The accompanying condensed consolidated financial statements of the Company include the accounts of the wholly-owned subsidiaries and other subsidiaries in which the Company holds a controlling financial or management interest of which the Company determined that it is primary beneficiary. The Company uses the equity method of accounting for investments in entities in which the Company has an ownership interest between 20% and 50% and exercises significant influence. The Company also consolidates its pro rata share of oil and natural gas joint ventures. All significant intercompany accounts and transactions have been eliminated in consolidation.
7
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Use of Estimates
The preparation of condensed consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates underlying these financial statements include the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties and to evaluate the full cost pool in the ceiling test analysis.
Asset Retirement Obligation
On January 1, 2006, the Company adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” which is an interpretation of FASB Statement No. 143 “Accounting for Asset Retirement Obligations.” Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value can be reasonably estimated. The Company estimates a fair value of the obligation on each well in which it owns an interest by identifying costs associated with the future dismantlement and removal of production equipment and facilities and the restoration and reclamation of a field’s surface to a condition similar to that existing before oil and natural gas extraction began.
In general, the amount of an Asset Retirement Obligation (“ARO”) and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the Company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis within the related full cost pool.
Effective January 1, 2007, the accretion of the ARO on producing wells was adjusted for a change in the estimated life of the wells based on a reserve study prepared by an independent reserve engineering firm. The estimated life of the wells was increased by 10 years to an estimated life of 50 years per well. The accretion expense is included in interest expense and the depreciation expense is included in depreciation, depletion, and amortization in the consolidated statements of operations.
The following table sets forth a reconciliation of the Company’s ARO liability:
Three Months Ended March 31, | 2007 | 2006 | |||||
Beginning balance | $ | 1,331,893 | $ | 812,634 | |||
Liabilities incurred | 67,338 | - | |||||
Liabilities settled | (34,293 | ) | - | ||||
Accretion expense | 18,895 | 15,237 | |||||
Revisions of estimated liabilities | (617,163 | ) | - | ||||
Ending balance | $ | 766,670 | $ | 827,871 |
8
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Derivative Instruments
The Company’s results of operations and operating cash flows are impacted by the fluctuations in the market prices of natural gas. To mitigate a portion of the exposure to adverse market changes, the Company will periodically enter into various derivative instruments with a major financial institution. The purpose of the derivative instrument is to provide a measure of stability to the Company’s cash flow in meeting financial obligations while operating in a volatile natural gas market environment. The derivative instrument reduces the Company’s exposure on the hedged production volumes to decreases in commodity prices and limits the benefit the Company might otherwise receive from any increases in commodity prices on the hedged production volumes.
The Company recognizes all derivative instruments as assets or liabilities in the balance sheet at fair value. The accounting treatment for changes in fair value, as specified in SFAS No. 133 “Accounting for Derivative Investments and Hedging Activities,” is dependent upon whether or not a derivative instrument is designated as a hedge. For derivatives designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in Accumulated Other Comprehensive Income on the accompanying balance sheet until the hedged item is recognized in earnings as natural gas revenue. If the hedge has an ineffective portion, that particular portion of the gain or loss would be immediately reported in earnings. The following natural gas contracts were in place as of March 31, 2007:
Period | Type of Contract | Natural Gas Volume per Day | Price per mmbtu | Fair Value Asset (Liability) | |||||||||
April 2007—December 2008 | Swap | 5,000 mmbtu | $ | 9.00 | $ | 1,539,680 | |||||||
April 2007—December 2008 | Collar | 2,000 mmbtu | $ | 7.55/9.00 | (131,640 | ) | |||||||
Total Estimated Fair Value | $ | 1,408,040 |
For the three months ended March 31, 2007, the Company has recognized in Comprehensive Income changes in fair value of $3,027,593 on the contracts that have been designated as cash flow hedges on forecasted sales of natural gas. See “Comprehensive Income (Loss)” found in this note section. In addition, for the three months ended March 31, 2007, and 2006, the Company recognized $785,000 and $0, respectively, net gains from hedging activities included in oil and natural gas revenues.
Financial Instruments
The Company’s financial instruments consist primarily of cash, accounts receivable, loans receivable, accounts payable, accrued expenses, and debt. The carrying amounts of such financial instruments approximate their respective estimated fair value due to the short-term maturities and approximate market interest rates of these instruments.
Stock-Based Compensation
On January 1, 2006, the Company adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R), to account for stock-based employee compensation. Among other items, SFAS No. 123R eliminates the use of Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees,” and the intrinsic value method of accounting and requires companies to recognize the cost of employee services received in exchange for stock-based awards based on the grant date fair value of those awards in their financial statements. The Company elected to use the modified prospective method for adoption, which requires compensation expense to be recorded for all unvested stock options beginning in the first quarter of adoption. For stock-based awards granted or modified subsequent to January 1, 2006, compensation expense, based on the fair value on the date of grant, will be recognized in the financial statements over the vesting period. The Company utilizes the Black-Scholes option pricing model to measure the fair value of stock options. To the extent compensation cost relates to employees directly involved in oil and natural gas exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expenses. See Note 8 “Common Stock Options” which fully describes the Company’s stock-based compensation plans.
9
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following stock-based compensation was recorded for the periods indicated:
For the Three Months Ended March 31, | 2007 | 2006 | |||||
General and administrative expenses | $ | 594,044 | $ | 157,392 | |||
Oil and natural gas properties | 67,336 | 213,074 | |||||
Total | $ | 661,380 | $ | 370,466 |
Comprehensive Income (Loss)
Comprehensive income (loss) is comprised of net income and other comprehensive income. Other comprehensive income includes income resulting from derivative instruments designated as hedging transactions. The details of comprehensive income (loss) are as follows for the periods indicated:
Three Months Ended March 31, | 2007 | 2006 | |||||
Net loss | $ | (740,319 | ) | $ | (939,183 | ) | |
Other comprehensive income: | |||||||
Change in fair value of derivative instruments | (3,027,593 | ) | - | ||||
Comprehensive Income (Loss) | $ | (3,767,912 | ) | $ | (939,183 | ) |
Income (Loss) Per Share
Basic net income (loss) per common share is computed based on the weighted average number of common shares outstanding during each period. Diluted net income (loss) per common share is computed based on the weighted average number of common shares outstanding plus other dilutive securities, such as stock options, warrants, and redeemable convertible preferred stock. All dilutive securities were excluded in the computation of diluted loss per share because their effect of assumed exercises or conversions was anti-dilutive and, accordingly, basic and dilutive weighted average shares are the same.
NOTE 3. | RECENT ACCOUNTING PRONOUNCEMENTS |
On February 15, 2007, the FASB issued SFAS No. 159, “Fair Value Option for Financial Assets and Financial Liabilities”—including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. The FASB believes the statement will improve financial reporting by providing companies the opportunity to mitigate volatility in reported earnings by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Use of the statement will expand the use of fair value measurements for accounting for financial instruments. The Company does not believe SFAS No. 159 will have a material impact on its consolidated financial statements.
10
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 4. | ACQUISITIONS AND DISPOSITIONS |
2007 - Kansas Project
On February 7, 2007, the Company entered into a Purchase and Sale Letter Agreement to sell to Harvest Energy, LLC all of the Company’s interest in various developed and undeveloped oil and natural gas properties located in Lane and Ness Counties in the State of Kansas for approximately $1.0 million. The properties included two net wells, 98 mmcfe in proven reserves, and approximately 23,110 net acres. This transaction closed on March 9, 2007.
NOTE 5. | OIL AND NATURAL GAS PROPERTIES HELD FOR SALE |
Management is currently in the process of evaluating the Company’s property portfolio to ensure that the oil and natural gas properties portfolio properly matches the Company’s long-term strategic plan. During the second quarter of 2006, the Company identified certain leasehold properties as held for sale due to their high probability of being sold within the next 12 months. Total oil and natural gas properties held for sale before depletion amounted to $5,488,140 at March 31, 2007, of which $4,448,499 is proved and $1,039,641 is unproved. (See Note 4 “Acquisitions and Dispositions.”) These properties are carried at the lower of historical cost or fair value. Under the full cost method, sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. The Company has evaluated the proved reserves of these properties (948 mmcfe as of March 31, 2007) and determined that there is no significant effect on the proved reserves regarding the assets held for sale.
NOTE 6. | DEBT |
Short-Term Bank Borrowings
The Company has a $5.0 million revolving line of credit agreement with Northwestern Bank for general corporate purposes. As of March 31, 2007, our total borrowing capacity available under this facility was $5.0 million. To secure this line of credit, two trusts controlled by an executive officer pledged certain shares of the Company’s common stock under his control. The interest rate under the revolving line of credit is Wall Street prime (8.25% and 7.75% at March 31, 2007, and 2006, respectively) with interest payable monthly in arrears. Principal is payable at the expiration of the revolving line of credit agreement. Northwestern Bank has extended the expiration date to October 15, 2007. Northwestern Bank also provides letters of credit for the drilling program (as described in Note 9 “Commitments and Contingencies”). Interest expense on the Northwestern Bank revolving line for the three months ended March 31, 2007, and 2006, were $867 and $106,626, respectively.
Short-Term Bank Borrowings - Bach Services & Manufacturing Co. L.L.C. (“Bach”)
On October 6, 2006, Bach entered into a $175,100 revolving line of credit agreement with Northwestern Bank for general company purposes. Effective April 16, 2007, Northwestern Bank increased the borrowing capacity under the revolving line of credit to $0.5 million. This line of credit is secured by all of Bach’s personal property owned or hereafter acquired and is non-recourse to the Company. The interest rate under the revolving line of credit is Wall Street prime (8.25% at March 31, 2007) with interest payable monthly in arrears. Principal is payable at the expiration of the revolving line of credit agreement. The expiration date is October 1, 2007. Interest expense for the three months ended March 31, 2007, was $1,163.
11
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Mortgage and Notes Payable - Bach
As of March 31, 2007, the Bach outstanding loans were as follows with interest expense for the three months ended March 31, 2007:
Description of Loan | Date of Loan | Maturity Date | Interest Rate | Principal Amount Outstanding | Interest Expense | |||||||||||
Mortgage payable on building | 10/06/06 | 10/15/09 | 6.00 | % | $ | 377,635 | $ | 5,930 | ||||||||
Notes payable | ||||||||||||||||
Vehicles | 10/06/06 | 10/01/10 | 7.50 | % | 84,592 | |||||||||||
Equipment | 10/06/06 | 09/01/07 | 5.50 | % | 7,688 | |||||||||||
Vehicles | 12/18/06 | 12/20/09 | 7.25 | % | 64,855 | |||||||||||
Total notes payable | $ | 157,135 | $ | 3,068 |
Mortgage Payable
On October 4, 2005, the Company entered into a mortgage loan from Northwestern Bank in the amount of $2,925,000 for the purchase of an office condominium and associated interior improvements. The security for this mortgage is the office condominium real estate. The payment schedule is monthly interest only for the first 3 months starting on November 1, 2005, and, beginning on February 1, 2006, principal and interest in 32 monthly payments of $21,969 with one principal and interest payment of $2,733,994 on October 1, 2008. The interest rate is 6.5% per year. The maturity date is October 1, 2008. As of March 31, 2007, the principal amount outstanding was $2,765,007. Interest expense for the three months ended March 31, 2007, and 2006, was $36,252 and $52,465, respectively.
Note Payable - Directors and Officers Insurance
On November 13, 2006, the Company entered into a financing agreement with AICCO, Inc. to finance the insurance premium related to director and officer liability insurance coverage in the amount of $184,230. A monthly payment of $15,807 is required beginning November 30, 2006, through August 1, 2007. The interest rate is 7.01% per year. As of March 31, 2007, the principal amount outstanding was $77,672. Interest expense for the three months ended March 31, 2007, was $1,182.
Mezzanine Financing
The Company has a 5-year $50 million mezzanine credit facility with Trust Company of the West (“TCW”) for the Michigan Antrim drilling program. The borrower is Aurora Antrim North (“North”), a wholly owned subsidiary of the Company. Upon closing of the BNP Paribas (“BNP”) senior secured credit facility discussed below, TCW now holds a second lien position in the Michigan Antrim natural gas properties. The interest rate is fixed at 11.5% per year, compounded quarterly, and payable in arrears. Beginning September 28, 2006, and quarterly thereafter, the required principal payment is 75% (100% if coverage deficiency or default occurs) of adjusted net cash flow determined by deducting specific expenses, including capital expenditures from “gross cash revenue.” The Company estimates that no principal payments on the mezzanine financing will be required until maturity because of the level of anticipated capital expenditures. The maturity date is September 30, 2009. The borrowing base is impacted by, among other factors, the fair value of the Company’s natural gas reserves that are pledged to TCW. Changes in the fair value of the natural gas reserves are caused by changes in prices for natural gas, operating expenses, and the results of drilling activity. A significant decline in the fair value of these reserves could reduce the borrowing base, and the Company may not be able to meet certain facility covenants.
12
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The mezzanine credit facility contains, among other things, certain covenants relating to restricted payments (as defined), loans or advances to others, additional indebtedness, and incurrence of liens and provides for the maintenance of certain financial and operating ratios, including current ratio and specified coverage ratios (collateral coverage and proved developed producing reserves coverage ratios).
As part of the mezzanine credit facility, the Company provided an affiliate of TCW an overriding royalty interest in certain properties to be drilled or developed in the Counties of Alcona, Alpena, Charlevoix, Cheboygan, Montmorency, and Otsego in the State of Michigan. The overriding royalty interest is 4%, subject to certain adjustments.
For the three months ended March 31, 2007, and 2006, interest and fees expensed for the mezzanine credit facility was $1,175,417 and $1,200,972, respectively.
Senior Secured Credit Facility
On January 31, 2006, the Company entered into a senior secured credit facility with BNP for drilling, development, and acquisitions, as well as other general corporate purposes. The borrower is North with a current borrowing base of $50 million. As proved reserves are added, this borrowing base may increase to $100 million with TCW consent. A required semiannual reserve report may result in an increase or decrease in credit availability. The security for this facility is a first lien position in certain Michigan Antrim assets; a guarantee from Aurora; and a guarantee from the Company secured by a pledge of its stock in Aurora. This facility matures the earlier of January 31, 2010, or 91 days prior to the maturity of the mezzanine credit facility, unless the Company elects to terminate the commitment earlier pursuant to the terms of the senior secured credit facility.
This facility provides for borrowings tied to BNP’s prime rate (or, if higher, the federal funds effective rate plus 0.5%) or LIBOR-based rate plus 1.25% to 2.0% depending on the borrowing base utilization, as selected by the Company. The borrowing base utilization is the percentage of the borrowing base that is drawn under the senior secured credit facility from time to time. As the borrowing base utilization increases, the LIBOR-based interest rates increase under this facility. As of March 31, 2007, interest on the borrowings had a weighted average interest rate of 7.125%. For the three months ended March 31, 2007, and 2006, interest and fees expensed for the senior secured credit facility was $388,225 and $392,230, respectively.
The senior secured credit facility contains, among other things, a number of financial and non-financial covenants relating to restricted payments (as defined), loans or advances to others, additional indebtedness, incurrence of liens, a prohibition on the Company’s ability to prepay the mezzanine credit facility, geographic limitations on operations to the United States, and maintenance of certain financial and operating ratios, including current ratio and specified coverage ratios (collateral coverage and proved developed producing reserves coverage ratios). Effective December 21, 2006, the senior secured credit facility was amended to eliminate the interest coverage ratio covenant for the fiscal quarter ending December 31, 2006, and to modify the 2007 fiscal quarters’ interest coverage ratio covenants.
The Company has incurred deferred financing fees of approximately $406,000 from BNP and approximately $2,850,000 from TCW. The deferred financing fees are being amortized on a straight-line basis over the remaining terms of each debt obligation. Amortization expense is estimated to be $0.8 million per year through 2009. Amortization expense was $218,234 and $214,976 for the three months ended March 31, 2007, and 2006, respectively. In addition, the Company incurs various annual fees associated with unused commitment and agency fees. These annual fees are recorded to interest expense.
13
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The Company capitalizes interest on debt related to expenditures made in connection with exploration and development projects that are not subject to the full cost amortization pool. Interest is capitalized only for the period that exploration activities are in progress. Interest is capitalized using a weighted average interest rate based on the outstanding borrowing, and cost of equity of the Company. Capitalized interest was $869,810 and $400,774 for the three months ended March 31, 2007, and 2006, respectively.
NOTE 7. | SHAREHOLDERS’ EQUITY |
Common Stock
In January 2007, 78,158 shares of the Company’s common stock were issued in connection with the exercise of outstanding warrants by an outside party in a net issue (cashless) exercise transaction.
In February and March 2007, 60,000 common stock options were exercised by various Company employees under the existing stock option plans at an exercise price of $0.375 per share. The Company received $22,500 in conjunction with this exercise.
In February and March 2007, 93,332 common stock options were exercised by various Company directors under the existing stock option plans at an exercise price of $0.375 per share. The Company received $35,000 in conjunction with these exercises.
Common Stock Warrants
The following table provides information related to stock warrant activity for the three months ended March 31, 2007:
Number of Shares Underlying Warrants | Weighted Average Exercise Price | Weighted Average Contract Life in Years | ||||||||
Outstanding at the beginning of the period | 2,079,500 | $ | 1.71 | 1.98 | ||||||
Granted | - | |||||||||
Exercised | (78,158 | ) | (1.25 | ) | 0.24 | |||||
Forfeitures and other adjustments | (49,342 | ) | (1.25 | ) | 0.24 | |||||
Outstanding at the end of the period | 1,952,000 | $ | 1.74 | 1.84 |
NOTE 8. | COMMON STOCK OPTIONS |
As of March 31, 2007, the Company maintains four stock option plans that are fully described in Note 8 “Common Stock Options” in the Company’s Annual Report on Form 10-KSB for the year-ended December 31, 2006. These stock option plans provide for the award of options or restricted shares for compensatory purposes. The purpose of these plans is to promote the interests of the Company by aligning the interests of employees (including directors and officers who are employees), consultants, and non-employee directors of the Company and to provide incentives for such persons to exert maximum efforts for the success of the Company and its subsidiaries.
14
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table provides activity for the stock option plans referenced above for the three months ended March 31, 2007:
Number of Shares Underlying Options | ||||
Options outstanding at beginning of period | 3,432,496 | |||
Options granted | 185,000 | |||
Options exercised | (153,332 | ) | ||
Options forfeited and other adjustments | - | |||
Options outstanding at end of period | 3,464,164 |
The weighted average assumptions used in the Black-Scholes option-pricing model used to determine fair value were as follows:
Risk-free interest rate | 4.1 | % | ||
Expected years until exercise | 2.5-6.0 | |||
Expected stock volatility | 43.0 | % | ||
Dividend yield | 0 | % |
All Stock Options
In addition, the Company has awarded compensatory options and warrants totaling 1,430,280 on an individualized basis that was considered outside the awards issued under its existing stock option plans. The following table provides activity with respect to all stock options awarded for the three months ended March 31, 2007:
Number of Shares Underlying Options | Weighted Average Exercise Price | Aggregate Intrinsic Value(a) | ||||||||
Options outstanding at beginning of period | 4,862,776 | $ | 2.23 | |||||||
Options granted | 185,000 | 3.35 | ||||||||
Options exercised | (153,332 | ) | 0.38 | |||||||
Forfeitures and other adjustments | (9,000 | ) | 4.70 | |||||||
Options outstanding at end of period | 4,885,444 | $ | 2.33 | $ | 4,550,000 | |||||
Exercisable at end of period | 2,992,277 | $ | 1.37 | $ | 4,532,000 | |||||
Weighted average fair value of options granted during period | $ | 1.20 |
(a) The intrinsic value of a stock option is the amount by which the current market value of the underlying stock exceeds the exercise price of the option. The intrinsic value of the options exercised during the three months ended March 31, 2007, was approximately $343,000.
15
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table provides the unrecognized compensation cost related to unvested stock options as of March 31, 2007. The cost is expected to be recognized over the following 3-year period.
Period to be Recognized | 2007 | 2008 | 2009 | 2010 | Total Unrecognized Compensation Cost | |||||||||||
1st Quarter | $ | - | $ | 428,053 | $ | 31,996 | $ | 1,146 | ||||||||
2nd Quarter | 610,395 | 360,689 | 14,664 | - | ||||||||||||
3rd Quarter | 587,474 | 117,728 | 5,194 | - | ||||||||||||
4th Quarter | 547,100 | 97,844 | 2,893 | - | ||||||||||||
Total | $ | 1,744,969 | $ | 1,004,314 | $ | 54,747 | $ | 1,146 | $ | 2,805,176 | ||||||
The weighted average remaining life by exercise price as of March 31, 2007, is summarized below:
Range of Exercise Prices | Outstanding Shares | Weighted Average Life | Exercisable Shares | Weighted Average Life | ||||
$0.25 - $0.38 | 596,664 | 3.9 | 596,664 | 3.9 | ||||
$0.50 - $0.75 | 1,440,000 | 1.9 | 1,440,000 | 1.9 | ||||
$1.25 - $1.75 | 352,000 | 7.4 | 352,000 | 7.4 | ||||
$2.23 - $3.55 | 498,280 | 7.0 | 110,280 | 2.6 | ||||
$3.62 | 1,140,000 | 3.8 | 300,000 | 3.6 | ||||
$4.45 - $4.70 | 658,500 | 8.6 | 33,333 | 5.8 | ||||
$5.19 - $5.54 | 200,000 | 4.7 | 160,000 | 4.3 | ||||
$0.25 - $5.54 | 4,885,444 | 4.5 | 2,992,277 | 3.2 |
NOTE 9. | COMMITMENTS AND CONTINGENCIES |
Environmental Risk
Due to the nature of the oil and natural gas business, the Company is exposed to possible environmental risks. The Company manages its exposure to environmental liabilities for both properties it owns as well as properties to be acquired. The Company has historically not experienced any significant environmental liability and is not aware of any potential material environmental issues or claims at March 31, 2007.
Letters of Credit
For each salt water disposal well drilled in the State of Michigan, the Company is required to issue a letter of credit to the Michigan Supervisor of Wells. The Supervisor of Wells may draw on the letter of credit if the Company fails to comply with the regulatory requirements relating to the locating, drilling, completing, producing, reworking, plugging, filling of pits, and clean up of the well site. The letter of credit or a substitute financial instrument is required to be in place until the salt water disposal well is plugged and abandoned. For drilling natural gas wells, the Company is required to issue a blanket letter of credit to the Michigan Supervisor of Wells. This blanket letter of credit allows the Company to drill an unlimited number of natural gas wells. The existing letters of credit have been issued by Northwestern Bank of Traverse City, Michigan, and are secured only by a Reimbursement and Indemnification Commitment issued by the Company, together with a right of setoff against all of the Company’s deposit accounts with Northwestern Bank. At March 31, 2007, letters of credit in the amount of $1,186,100 were outstanding to the Michigan Supervisor of Wells.
16
AURORA OIL & GAS CORPORATION AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Employment Agreement
Effective June 19, 2006, the Company hired Ronald E. Huff to serve as Chief Financial Officer of the Company. The Company has entered into a 2-year Employment Agreement with Mr. Huff, providing for an annual salary of $200,000 per year and an award of a stock bonus in the amount of 500,000 shares of the Company’s common stock on January 1, 2009, so long as he remains employed by the Company through June 18, 2008, which requires the Company to record approximately $2.1 million in stock-based compensation expense over the contract period. If his employment with the Company is terminated prior to this date without just cause or if the Company undergoes a change in control, he will nonetheless be awarded the full 500,000 shares. If his employment is terminated prior to June 18, 2008, due to death or disability, he will receive a prorated stock award. Mr. Huff forfeited the option to purchase 200,000 shares that he was previously awarded for his service as a director of the Company. Mr. Huff remains a director of the Company.
Fry Well Contingency
The Company is a participant with Savoy Energy, L.P. (“Savoy”) in a well known as the Fry 1-13 located in Mecosta County, Michigan. In late December 2006, the well experienced a blow-out event. Savoy currently is estimating costs of approximately $5.6 million for expenses associated with controlling the well and other related costs. The Company has a 13.33% cost interest (10% working interest) in this well to casing point and has recorded approximately $0.8 million to cover its portion of the loss.
17
ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
You should read the following discussion in conjunction with management’s discussion and analysis contained in our 2006 Annual Report on Form 10-KSB, as well as the condensed consolidated financial statements and notes hereto included in this quarterly report on Form 10-Q. The following discussion contains forward-looking statements that involve risks, uncertainties, and assumptions, such as statements of our plans, objectives, expectations, and intentions. Our actual results may differ materially from those discussed in these forward-looking statements because of the risks and uncertainties inherent in future events.
Overview
We are a growing independent energy company focused on the exploration, exploitation, and development of unconventional natural gas reserves. Our unconventional natural gas projects target shale plays where large acreage blocks can be easily evaluated with a series of low cost test wells. Shale plays tend to be characterized by high drilling success and relatively low drilling costs when compared to conventional exploration and development plays. Our project areas are focused in the Antrim shale of Michigan and New Albany shale of Southern Indiana and Western Kentucky.
We commenced operations in 1969 to explore and mine natural resources under the name Royal Resources, Inc. In July 2001, we reorganized our business to pursue oil and gas exploration and development opportunities and changed our name to Cadence Resources Corporation. We acquired Aurora Energy, Ltd. (“Aurora”) on October 31, 2005, through the merger of our wholly-owned subsidiary with and into Aurora. The acquisition of Aurora was accounted for as a reverse merger with Aurora being the acquiring party for accounting purposes. The Aurora executive management team also assumed management control at the time the merger closed, and we moved our corporate offices to Traverse City, Michigan. Effective May 11, 2006, Cadence Resources Corporation amended its articles of incorporation to change the parent company name to Aurora Oil & Gas Corporation.
Our revenue, profitability and future rate of growth are substantially dependent on our ability to find, develop, and acquire gas reserves that are economically recoverable based on prevailing prices of natural gas and oil. Historically, the energy markets have been very volatile, and it is likely that oil and natural gas prices will continue to be subject to wide fluctuations in the future. A substantial or extended decline in natural gas and oil prices could have a material adverse effect on our financial position, results of operations, cash flows, access to capital and on the quantities of natural gas and oil that can be economically produced.
Highlights
For the three months ended March 31, 2007, we continued to shift our focus from acquisition of properties to an early stage developer of low risk shale development projects. As of March 31, 2007, our leasehold acres (both developed and undeveloped) were 1,287,450 (702,408 net) which represent a 2% increase over our December 31, 2006 net acres. Of the 70,670 (12,518 net) leasehold acres acquired, 2,594 net acres were in the Antrim shale play and 15,693 net acres were in the New Albany shale play with a reduction of net acres in the Other play areas due to a disposition.
With regard to our strategy to generate growth through drilling, we drilled or participated in 35 (16 net) wells for the three months ended March 31, 2007, with an 89% success rate. Our Antrim drilling program was restricted for the first three months due to frost laws not allowing movement of drilling rigs. As of March 31, 2007, we had 483 (232 net) producing wells and 106 (54 net) wells awaiting hook-up. We also continued our strategy to have greater control over our projects by operating 225 (209 net) wells, thus, operating 38% of our gross wells and 73% of our net wells.
Oil and natural gas production for the three months ended March 31, 2007, was 732,430 mcfe, or 16% over the 633,958 mcfe produced in the three months ended March 31, 2006. For the three months ended March 31, 2007, production continues to be hampered by curtailments on a third-party processing facility, delays bringing wells into production, and dewatering. The Company recently completed construction of its own processing facility and built an alternative pipeline route in response to the curtailment.
18
In order to reduce exposure to fluctuations in the price of natural gas, we will periodically enter into financial arrangements with a major financial institution. We have entered into a financial swap contract for 5,000 mmbtu per day at a fixed price of $9.00 per mmbtu for the period from April 2007 through December 2008 and a costless collar contract for 2,000 mmbtu per day with a ceiling price of $9.00 per mmbtu and a floor price of $7.55 per mmbtu for the period from April 1, 2007, through December 31, 2008. These derivative instruments provide the Company with a weighted average floor price of $8.59 per mmbtu per day on 7,000 mmbtu per day.
(Intentionally Left Blank)
19
Operating Statistics
The following table sets forth certain key operating statistics for the three months ended March 31, 2007 (the “Current Quarter’), and the three months ended March 31, 2006 (the “Prior Quarter”):
Increase (Decrease) | |||||||||||||
2007 | 2006 | Amount | Percent | ||||||||||
Net wells drilled | |||||||||||||
Antrim shale | 8 | 9 | (1 | ) | (11 | %) | |||||||
New Albany shale (“NAS”) | - | 2 | (2 | ) | (100 | %) | |||||||
Other | 4 | - | 4 | 100 | % | ||||||||
Dry | 4 | 2 | 2 | 100 | % | ||||||||
Total | 16 | 13 | 3 | 23 | % | ||||||||
Total net wells | |||||||||||||
Antrim—producing | 219 | 116 | 103 | 89 | % | ||||||||
Antrim—awaiting hookup | 42 | 50 | (8 | ) | (16 | %) | |||||||
NAS—producing | 1 | - | 1 | 100 | % | ||||||||
NAS—awaiting hookup | 7 | 3 | 4 | 133 | % | ||||||||
Other—producing | 12 | 15 | (3 | ) | (20 | %) | |||||||
Other—awaiting hookup | 5 | 2 | 3 | 150 | % | ||||||||
Total | 286 | 186 | 100 | 54 | % | ||||||||
Production | |||||||||||||
Natural gas (mcf) | 690,435 | 594,346 | 96,089 | 16 | % | ||||||||
Crude oil (bbls) | 6,999 | 6,602 | 397 | 6 | % | ||||||||
Natural gas equivalent | 732,430 | 633,958 | 98,472 | 16 | % | ||||||||
Average daily production | |||||||||||||
Natural gas (mcf) | 7,672 | 6,604 | 1,068 | 16 | % | ||||||||
Crude oil (bbls) | 78 | 73 | 5 | 7 | % | ||||||||
Natural gas equivalent | 8,140 | 7,042 | 1,098 | 16 | % | ||||||||
Average sales price includes effects of realized hedging | |||||||||||||
Natural gas (mcf) | $ | 8.01 | $ | 8.49 | $ | (0.48 | ) | (6 | %) | ||||
Crude oil (bbls) | $ | 53.74 | $ | 56.27 | $ | (2.53 | ) | (5 | %) | ||||
Natural gas equivalent | $ | 8.10 | $ | 8.54 | $ | (0.44 | ) | (5 | %) | ||||
Production revenue | |||||||||||||
Natural gas | $ | 5,553,439 | $ | 5,045,383 | $ | 508,056 | 10 | % | |||||
Crude oil | 376,137 | 371,483 | 4,654 | 1 | % | ||||||||
Total | $ | 5,929,576 | $ | 5,416,866 | $ | 512,710 | 9 | % | |||||
Average expenses ($ per mcfe) | |||||||||||||
Production taxes | $ | 0.36 | $ | 0.34 | $ | 0.02 | 6 | % | |||||
Post-production expenses | $ | 0.39 | $ | 0.52 | $ | (0.13 | ) | (25 | %) | ||||
Lease operating expenses | $ | 2.24 | $ | 2.09 | $ | 0.14 | 7 | % | |||||
General and administrative expense | $ | 3.09 | $ | 2.47 | $ | 0.62 | 25 | % | |||||
General and administrative expense excluding stock-based compensation | $ | 2.28 | $ | 2.22 | $ | 0.06 | 3 | % | |||||
Oil and natural gas depreciation, depletion and amortization expenses | $ | 1.02 | $ | 1.49 | $ | (0.47 | ) | (32 | %) | ||||
Other assets depreciation and amortization | $ | 0.78 | $ | 0.74 | $ | 0.04 | 5 | % | |||||
Interest expenses | $ | 1.34 | $ | 2.51 | $ | 1.17 | (47 | %) | |||||
Taxes | $ | (0.03 | ) | $ | - | $ | 0.03 | (100 | %) | ||||
Number of employees | 90 | 44 | 46 | 105 | % |
20
Results of Operations
Three Months Ended March 31, 2007, compared with Three Months Ended March 31, 2006
General. For the Current Quarter, the Company had a net loss of $0.7 million, or $(0.01) per diluted common share, on total revenues of $6.3 million. This compares to a net loss of $0.9 million, or $(0.01) per diluted common share, on total revenue of $5.6 million for the Prior Quarter. The $0.7 million increase in revenue represents our initial steps as an early stage developer of oil and natural gas properties.
Oil and Natural Gas Sales. During the Current Quarter, oil and natural gas sales were $5.9 million compared to $5.4 million in the Prior Quarter. The Company produced 732,430 mcfe at a weighted average price of $8.10 compared to 633,958 mcfe at a weighted average price of $8.54. This increase in production was due to new wells placed on-line. We had 232 net wells producing as of March 31, 2007, as compared to 131 net wells producing as of March 31, 2006. The weighted average price included $0.8 million of realized gains from the gas derivative contract. Production from the Antrim shale play represented approximately 92% of our oil and natural gas revenue for the Current Quarter.
The following table summarizes our oil and natural gas revenue by play/trend in the periods set forth below:
Three Months Ended March 31, 2007 | Three Months Ended March 31, 2006 | ||||||||||||
Play/Trend | (mcfe) | Amount | (mcfe) | Amount | |||||||||
Antrim | 675,353 | $ | 5,455,370 | 533,419 | $ | 4,353,977 | |||||||
New Albany | 10,344 | 74,400 | 2,483 | 19,994 | |||||||||
Other | 46,733 | 399,806 | 98,056 | 1,042,895 | |||||||||
Total | 732,430 | $ | 5,929,576 | 633,958 | $ | 5,416,866 |
Other Revenues. Other revenues increased by $0.1 million, or 99% to $0.3 million in the Current Quarter from $0.2 million in the Prior Quarter. This increase is attributed to the Bach acquisition in 2006 which provides oil and natural gas field services.
Production Taxes. Production taxes were $0.3 million in the Current Quarter compared to $0.2 million in the Prior Quarter. This increase is attributed to new wells being added and production growth of existing wells. On a unit of production basis, production taxes were $0.36 per mcfe in the Current Quarter compared to $0.34 per mcfe in the Prior Quarter.
Production and Lease Operating Expenses. Our production and lease operating expenses include services related to producing oil and natural gas, such as post-production costs, including marketing and transportation, and expenses to operate the wells and equipment on producing leases.
Production and lease operating expenses were $1.9 million in the Current Quarter compared to $1.7 million in the Prior Quarter. On a per unit of production basis, production and lease operating expenses were $2.63 per mcfe in the Current Quarter compared to $2.61 per mcfe in the Prior Quarter. The increase in the Current Quarter was primarily attributable to higher energy costs, higher pumping costs, repair and maintenance associated with compressors and pumps, and outside labor. On a component basis, post-production expenses were $0.3 million, or $0.39 per mcfe, in the Current Quarter compared to $0.3 million, or $0.52 per mcfe, in the Prior Quarter, and lease operating expenses were $1.6 million, or $2.24 per mcfe, in the Current Quarter compared to $1.3 million, or $2.09 per mcfe, in the Prior Quarter. Production and lease operating expenses for operated properties were $2.37 per mcfe in the Current Quarter while non-operated production and lease operating expenses were $3.33 per mcfe in the Current Quarter.
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Pipeline Operating Expenses and Field Services Expenses. Pipeline operating expenses were $0.1 million in the Current Quarter compared to $0.1 million in the Prior Quarter. Field services expenses were $0.2 million in the Current Quarter compared to no expense in the Prior Quarter which are attributable to the Bach acquisition in October 2006.
General and Administrative Expenses. Our general and administrative expenses include officer and employee compensation, travel, audit, tax and legal fees, office supplies, utilities, insurance, consulting fees, and office related expense. General and administrative expenses in the Current Quarter increased by $0.7 million, or 44%, from the Prior Quarter. This increase is the result of executing our growth strategy. This has resulted in substantial increases in employees and related cost. Our staffing requirements increased 39% to 61 employees for the Current Quarter compared to 44 employees in the Prior Quarter which excludes 29 employees from the Bach acquisition.
Payroll and related costs increased by $1.0 million to $1.5 million in the Current Quarter. This included stock-based compensation of $0.6 million in the Current Quarter which consists of $0.1 million for directors, $0.3 million for senior management and $0.2 million for employees. We reduced legal, accounting, and other consulting services by $0.4 million to $0.4 million in the Current Quarter compared to $0.8 million in the Prior Quarter.
The Company follows the full cost method of accounting under which all costs associated with property acquisition, exploration, and development activities are capitalized. We capitalized certain internal costs that can be directly identified with our acquisition, exploration, and development activities and do not include any costs related to production, general corporate overhead, or similar activities. We capitalized $0.5 million of payroll and benefit costs for the Current Quarter compared to $0.6 million in the Prior Quarter.
Oil and Natural Gas Depletion, Depreciation and Amortization (“DD&A”). DD&A of oil and natural gas properties was $0.7 million and $0.9 million during the Current Quarter and the Prior Quarter, respectively. DD&A is a function of capitalized costs in the full cost pool and related underlying reserves in the periods presented. This decrease is the result of a change in estimate of DD&A from proven developed reserves to total proven reserves and the underlying reserves increasing by 89 bcfe as of December 31, 2006. The average DD&A cost per mcfe was $1.02 and $1.49 in the Current Quarter and the Prior Quarter, respectively.
Other Assets Depreciation and Amortization (“D&A”). D&A of other assets was $0.6 million in the Current Quarter, compared to $0.5 million in the Prior Quarter. This increase was primarily the result of additional investment in other assets.
Interest Expense. Interest expense was $1.0 million in the Current Quarter compared to $1.6 million in the Prior Quarter. This decrease is the result of a change in estimating capitalized interest and reduction in borrowing under the senior secured credit facility. During the fourth quarter 2006, the Company modified its approach to estimating capitalized interest by recognizing that debt need not be specific debt incurred on a specific asset.
Taxes, Other. Tax expense (refund) was ($25,182) in the Current Quarter compared to $1,667 in the Prior Quarter. This decrease primarily represents a 2003 Indiana property tax refund of $39,884 received in 2007. The Company has significant net operating loss carryforwards, thus no income tax expense has been recognized.
Liquidity and Capital Resources
We expect to fund our growth strategy using a combination of debt, existing cash balances, internally generated cash flows from natural gas production, and the proceeds from the 2006 equity offering. Our 2007 capital budget for drilling and related well work and infrastructure is estimated to be approximately $105.6 million with anticipated participation in 410 (228 net) wells. Our 2007 capital budget for leasehold interest and property acquisitions is estimated to be approximately $9.0 million and $1.0 million, respectively. We believe that the proceeds of the 2006 equity offering, our available credit facilities and our operating cash flow will be sufficient to fund our operations and capital expenditures for the next 12 months. However, future cash flows are subject to a number of variables, including the level of production and prices. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures.
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Our mezzanine financing is a $50 million credit facility with Trust Company of the West (“TCW”) for the Michigan Antrim shale drilling program. It has a maturity date of September 30, 2009. Borrowings under the TCW credit facility as of March 31, 2007 were $40 million with available borrowing capacity of $10 million. The interest rate is fixed at 11.5% per year, calculated and payable in arrears. Beginning September 28, 2006 and quarterly thereafter, the required principal payment is 75% (100% if coverage deficiency or default occurs) of Adjusted Net Cash Flow determined by deducting applicable operating expenses and capital expenditures from gross revenue. The TCW borrowing base is subject to semi-annual re-determination and certain other re-determinations based upon several factors. The borrowing base is impacted by, among other factors, the fair value of our natural gas reserves that are pledged to TCW. Changes in the fair value of our oil and natural gas reserves are caused by changes in prices for natural gas and crude oil, operating expenses and the results of drilling activity. A significant decline in the fair value of these reserves could cause us to be unable to meet certain facility covenants, which could result in a reduction in our borrowing base. The TCW loan agreement prohibits the declaration or payment of dividends and contains certain covenants. As of March 31, 2007, we were in compliance with all of the applicable covenants.
Our senior secured credit facility is a $100 million senior secured credit facility with BNP Paribas (“BNP”). The current borrowing base under this facility is $50 million and has not been updated for our 2006 year end reserves. As proved reserves are added, this borrowing base may increase up to $100 million with TCW consent. This facility matures the earlier of January 31, 2010, or 91 days prior to the maturity of the mezzanine credit facility. This facility provides for borrowings tied to prime rate or LIBOR plus 1.25 to 2.0% depending on the borrowing base utilization that we select. As of March 31, 2007, interest on borrowings under our senior credit facility had a weighted average interest rate of 7.125% and our total borrowings under this facility were $28 million. A required semi-annual reserve report may result in an increase or decrease in credit availability.
The senior secured credit facility contains, among other things, certain covenants relating to restricted payments, loans or advances to others, additional indebtedness, and incurrence of liens. It also provides for the maintenance of certain financial and operating ratios, including current ratio and specified coverage ratios (collateral coverage and proved developed producing reserves coverage ratios). Effective December 21, 2006, the senior secured credit facility was amended to eliminate the interest coverage ratio covenant for the fiscal quarter ending December 31, 2006, and to modify the 2007 fiscal quarters’ interest coverage ratio covenants. As of March 31, 2007, we were in compliance with all of the applicable covenants.
Our short-term line of credit is a $5 million revolving line of credit with Northwestern Bank for general corporate purposes. As of March 31, 2007, our total borrowing capacity available under this facility was $5.0 million. The interest rate is the prime rate with interest payable monthly in arrears. Principal is payable at the expiration of the line of credit, October 15, 2007.
Our total capitalization was as follows:
As of March 31, 2007 | As of December 31, 2006 | ||||||
Short-term bank borrowings | $ | 8,615 | $ | 542,788 | |||
Obligations under capital lease | 12,581 | 17,096 | |||||
Notes payable | 234,807 | 280,321 | |||||
Mortgage payables | 3,142,642 | 3,175,298 | |||||
Mezzanine financing | 40,000,000 | 40,000,000 | |||||
Senior secured credit facility | 28,000,000 | 10,000,000 | |||||
Total debt | 71,398,645 | 54,015,503 | |||||
Shareholders’ equity | 135,886,970 | 139,731,099 | |||||
Total capitalization | $ | 207,285,615 | $ | 193,746,602 |
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Cash Flows from Operating Activities
Cash provided by operating activities was $2.5 million in the Current Quarter, compared to cash used of $1.4 million in the Prior Quarter. The $2.5 million in net cash provided by operating activities was substantially due to the following; (1) $1.2 million received from joint interest partner for development projects; (2) $0.9 million transfer from drilling advances made by the Company; and (3) $0.4 million increase in production revenues. See “Results of Operations” for discussion of changes in revenues and expenses. Non-cash charges increased due to higher stock-based compensation. Changes in current operating assets and liabilities decreased cash flow from operations by $1.1 million which excludes the drilling and development activity.
Operating cash flows are impacted by many variables, the most significant of which are the volatility of prices for natural gas and oil produced and operational performance of our producing properties. Prices for these commodities are determined primarily by prevailing market conditions. As of March 31, 2007, we have entered into the following financial hedges: (i) 5,000 mmbtu per day at a price of $9.00 per mmbtu from April 2007 through December 2008, and (ii) a zero cost collar contract for 2,000 mmbtu per day with a cap price of $9.00 per mmbtu and a floor price of $7.55 per mmbtu for the period from April 1, 2007, through December 31, 2008. Based on our March 31, 2007, production exit rate of 8,725 mcfe per day, we have 80% of our existing production hedged through December 2008 with a weighted average floor price of $8.59 per mmbtu.
Cash Flows Used in Investing Activities
Cash flows used in investing activities was $19.5 million in the Current Quarter, compared to $42.7 million in the Prior Quarter. The following table describes our significant investing transactions that we completed in the periods set forth below:
Three Months Ended March 31 | |||||||
2007 | 2006 | ||||||
Acquisitions of leasehold | |||||||
Antrim shale | $ | 670,427 | $ | 2,692,996 | |||
New Albany shale(a) | 902,417 | 10,161,708 | |||||
Other | 1,195,902 | 954,775 | |||||
Drilling and development of oil and natural gas properties | |||||||
Antrim shale | 11,109,790 | 4,449,371 | |||||
New Albany shale | 664,567 | 1,221 | |||||
Other | 1,403,866 | 1,595,699 | |||||
Infrastructure properties | |||||||
Antrim shale | 3,454,053 | 1,858,490 | |||||
New Albany shale | 397,758 | - | |||||
Other | 563,799 | - | |||||
Acquisitions of oil and natural gas properties | - | 23,938,811 | |||||
Acquisitions/additions for pipeline, property, and equipment | 144,456 | 3,781,711 | |||||
Other, net | 37,412 | 270,986 | |||||
Subtotal of capital expenditures | 20,544,447 | 49,705,768 | |||||
Sale of oil and natural gas properties(a) | 1,025,000 | 6,990,681 | |||||
Subtotal of capital divestitures | 1,025,000 | 6,990,681 | |||||
Total | $ | 19,519,447 | $ | 42,715,087 |
(a) | On February 2, 2006, Aurora closed an acquisition of certain New Albany shale acreage located in Indiana, commonly called the Wabash project. Aurora acquired 64,000 acres of oil and natural gas leases from Wabash Energy Partners, L.P. for a purchase price of $11,840,000. The Company was required to deposit into escrow for the sellers $3.2 million in 2005. Aurora then sold half its interest in a combined 95,000 acre lease position in the Wabash project to New Albany-Indiana, L.L.C., an affiliate of Rex Energy Operating Corporation (“Rex”), for a sale price of $10,500,000. Rex placed $3.5 million in an escrow account in 2005 as a deposit until the closing in February 2006. |
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Cash Flows Provided by Financing Activities
Cash flows provided by financing activities were $17.4 million in the Current Quarter compared to $49.3 million in the Prior Quarter. Cash flows provided in the Current Quarter included: (1) $18.0 million of senior secured credit borrowing; and (2) $0.1 million of net proceeds received from exercise of common stock options and warrants. Cash flows used in the Current Quarter included: (1) net pay-down of $0.5 in short-term bank borrowings; (2) pay-down of $0.1 million in mortgage obligations; and (3) payment of $25,000 in financing fees.
Cash flows provided by financing activities in the Prior Quarter included: (1) $35.0 million of senior secured credit borrowing; and (2) $18.0 million of net proceeds received from exercise of common stock options and warrants. Cash flows used by financing in the Prior Quarter included: (1) net pay-down of $1.3 in short-term bank borrowings; (2) payments of $2.4 million in financing fees; and (3) pay-down of $15,594 in mortgage obligations and other.
Recent Accounting Pronouncements
Reference is made to Note 3 to the Financial Statements included elsewhere in this filing for a description of certain recently issued accounting pronouncements. We do not expect any of such recently issued accounting pronouncements to have a material effect on our consolidated financial position or results of operations.
Critical Accounting Policies
We consider accounting policies related to use of estimates, oil and natural gas properties, oil and natural gas reserves, stock-based compensation, and income taxes to be critical policies. These accounting policies are summarized in the audited consolidated financial statements and notes included in our Annual Report on Form 10-KSB for the year ended December 31, 2006.
Off Balance Sheet Arrangements
We have no special purpose entities, financing partnerships, guarantees, or off-balance sheet arrangements other than the outstanding letter of credits discussed in Note 9 “Commitments and Contingencies.”
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Commodity Price Risk
The Company’s results of operations and operating cash flows are impacted by the fluctuations in the market prices of natural gas. To mitigate a portion of the exposure to adverse market changes, the Company will periodically enter into various derivative instruments with a major financial institution. The purpose of the derivative instrument is to provide a measure of stability to the Company’s cash flow in meeting financial obligations while operating in a volatile natural gas market environment. The derivative instrument reduces the Company’s exposure on the hedged production volumes to decreases in commodity prices and limits the benefit the Company might otherwise receive from any increases in commodity prices on the hedged production volumes. The following natural gas contracts were in place as of March 31, 2007:
Period | Type of Contract | Natural Gas Volume per Day | Price per mmbtu | Fair Value Asset (Liability) | |||||||||
April 2007—December 2008 | Swap | 5,000 mmbtu | $ | 9.00 | $ | 1,539,680 | |||||||
April 2007—December 2008 | Collar | 2,000 mmbtu | $ | 7.55/9.00 | (131,640 | ) | |||||||
Total Estimated Fair Value | $ | 1,408,040 |
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Interest Rate Risk
The Company does not use interest rate derivatives to mitigate exposure to changes in interest rates. The following table sets forth the Company’s principal financing obligation and the related interest rates as of March 31, 2007:
Expected Maturity | Average Interest Rate as of March 31, 2006 | Principal Outstanding | ||||||||
Short-term bank borrowings | Revolving | Variable - 8.25% | $ | 8,615 | ||||||
Obligations under capital lease | 01/10/09 | 8.25% | 12,581 | |||||||
Notes payable | 08/01/07-10/01/10 | 5.50% - 7.50% | 234,807 | |||||||
Mortgage payable | 10/15/09 | Fixed at 6.00% | 377,635 | |||||||
Mortgage payable | 10/01/08 | Fixed at 6.50% | 2,765,007 | |||||||
Mezzanine financing | 09/30/09 | Fixed at 11.50% | 40,000,000 | |||||||
Senior secured credit facility | 01/31/10 | Variable - 7.125% | 28,000,000 | |||||||
Total debt | $ | 71,398,645 |
ITEM 4. | CONTROLS AND PROCEDURES |
Evaluation of Disclosure Controls and Procedures
Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in our periodic filings under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission's rules and forms, and that such information is accumulated and communicated to our management to allow timely decisions regarding required disclosure.
Our Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Securities Exchange Act of 1934, as amended) as of March 31, 2007, and have concluded that these disclosure controls and procedures are effective at the reasonable assurance level. Our CEO and CFO believe that the condensed consolidated financial statements included in this report on Form 10-Q fairly present in all material respects our financial condition, results of operations, and cash flows for the periods presented in conformity with generally accepted accounting principles.
Our management, including our CEO and CFO, do not expect that our internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met with respect to financial statement preparation and presentation. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or because the degree of compliance with the policies or procedures deteriorates.
Changes in Internal Controls over Financial Reporting
There have been no changes in our internal controls over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Our management continues to review our internal controls and procedures and the effectiveness of those controls. In the fourth quarter of 2006, the Company formally initiated the process of documenting internal controls over financial reporting in an effort to be in compliance with the evaluation and reporting requirements of the Sarbanes-Oxley Act of 2002 Section 404 by December 31, 2007.
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PART II
ITEM 1. | LEGAL PROCEEDINGS |
Our management is unaware of any threatened or pending material legal claims or procedures of a non-routine nature.
ITEM 1A. | RISK FACTORS |
Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock are described under “Risk Factors in Item 1 of our Annual Report on Form 10-KSB for the year ended December 31, 2006. This information should be considered carefully, together with other information in this report and other reports and materials we file with the Securities and Exchange Commission.
ITEM 2. | UNREGISTERED SALES OF EQUITY SECURITIES |
During the period from January 1, 2007, through March 31, 2007, we issued 78,158 shares of our common stock pursuant to an exercise of a warrant dated April 2, 2004, to purchase 127,500 shares of common stock. This exercise was made pursuant to a net issue election and the balance of the shares under the warrant was forfeited. The shares issued pursuant to the warrant exercise were issued in reliance on the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended.
We did not repurchase any of our outstanding equity securities during the quarter ended March 31, 2007.
ITEM 3. | DEFAULTS UPON SENIOR SECURITIES |
None.
ITEM 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
None.
ITEM 5. | OTHER INFORMATION |
None.
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ITEM 6. | EXHIBITS |
3.1(1) | Restated Articles of Incorporation of Aurora Oil & Gas Corporation. |
*3.2 | By-Laws of Aurora Oil & Gas Corporation. |
10.1 | Securities Purchase Agreement between Cadence Resources Corporation and the investors signatory thereto, dated April 2, 2004 (filed as Exhibit 99.3 to our Current Report on Form 8-K filed with the SEC on April 5, 2004, and incorporated herein by reference.) |
10.2 | Securities Purchase Agreement between Cadence Resources Corporation and the investors signatory thereto, dated January 31, 2005 (filed as Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on February 2, 2005, and incorporated herein by reference.) |
10.3(2) | Asset Purchase Agreement with Nor Am Energy, L.L.C., Provins Family, L.L.C. and O.I.L. Energy Corp. dated January 10, 2006. |
10.4 | Note Purchase Agreement between Aurora Antrim North, L.L.C. et al. and TCW Asset Management Company, dated August 12, 2004 (filed as an Exhibit to our Form S-4 registration statement filed with the SEC on May 13, 2005, and incorporated herein by reference.) |
10.5 | First Amended and Restated Note Purchase Agreement between Aurora Antrim North, L.L.C. et al. and TCW Asset Management Company, dated December 8, 2005 (filed as an Exhibit to our Annual Report on Form 10-KSB for the fiscal year ended September 30, 2005 filed with the SEC on December 29, 2005 and incorporated herein by reference.) |
10.6(2) | First Amendment to First Amended and Restated Note Purchase Agreement between Aurora Antrim North, L.L.C., et al., and TCW Asset Management Company, dated January 31, 2006. |
10.7(2) | Credit Agreement among Aurora Antrim North, L.L.C., et al. and BNP Paribas, et al., dated January 31, 2006. |
10.8(2) | Intercreditor and Subordination Agreement among BNP Paribas, et al., TCW Asset Management Company, and Aurora Antrim North, L.L.C., dated January 31, 2006. |
10.9(2) | Promissory Note from Aurora Energy, Ltd. to Northwestern Bank dated January 31, 2006. |
10.10(2) | Confirmation from BNP Paribas to Aurora Antrim North, L.L.C., dated February 22, 2006 relating to gas sale commitment. |
10.11 | 2006 Stock Incentive Plan. (filed as Exhibit 99.1 to our Form S-8 Registration Statement filed with the SEC on May 15, 2006 and incorporated herein by reference.) |
10.12(1) | Employment Agreement with Ronald E. Huff dated June 19, 2006. |
10.13(1) | Letter Agreement with Bach Enterprises dated July 10, 2006. This Agreement is confidential and has been filed separately with the SEC. |
10.14(1) | First Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated July 14, 2006. |
10.15(1) | The Denthorn Trust Commercial Guaranty of obligations to Northwestern Bank. |
10.16(1) | William W. Deneau Commercial Guaranty of obligations to Northwestern Bank. |
10.17(1) | The Denthorn Trust Commercial Pledge Agreement to Northwestern Bank. |
10.18(3) | LLC Membership Interest Purchase Agreement dated October 6, 2006 relating to Kingsley Development Company, L.L.C. |
10.19(3) | Asset Purchase Agreement with Bach Enterprises, Inc., et al., dated October 6, 2006. |
10.20(3) | Promissory Note from Aurora Energy, Ltd. to Northwestern Bank dated October 15, 2006. |
10.21(3) | Form of indemnification letter agreement between Aurora Oil & Gas Corporation and Rubicon Master Fund. |
10.22(3) | Patricia A. Deneau Trust Commercial Guaranty of obligations to Northwestern Bank. |
10.23(3) | Patricia A. Deneau Trust Commercial Pledge Agreement to Northwestern Bank. |
10.24 | Second Amendment to Credit Agreement between Aurora Antrim North, L.L.C., et al. and BNP Paribas dated December 21, 2006. (filed as an Exhibit 10.24 to our Annual Report on Form 10-KSB for the fiscal year ended December 31, 2006, filed with the SEC on March 15, 2007 and incorporated herein by reference.) |
*31.1 | Rule 13a-14(a) Certification of Principal Executive Officer. |
*31.2 | Rule 13a-14(a) Certification of Principal Financial and Accounting Officer. |
*32.1 | Section 1350 Certification of Principal Executive Officer. |
*32.2 | Section 1350 Certification of Principal Financial and Accounting Officer. |
* Filed with this Form 10-Q.
(1) | Filed as an exhibit to our Form 10-QSB for the period ended June 30, 2006, filed with the SEC on August 7, 2006, and incorporated herein by reference. |
(2) | Filed as an exhibit to our Form 10-KSB for the fiscal year ended December 31, 2005, filed with the SEC on March 31, 2006, and incorporated herein by reference. |
(3) | Filed on October 27, 2006, with our Amendment No. 3 to Form SB-2 registration statement filing, registration no. 333-137176, and incorporated herein by reference. |
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SIGNATURES
In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this quarterly report on Form 10-Q to be signed on its behalf by the undersigned thereto duly authorized.
AURORA OIL & GAS CORPORATION | ||
| | |
Date: May 14, 2007 | By: | /s/ William W. Deneau |
Name: William W. Deneau | ||
Title: President |
| | |
Date: May 14, 2007 | By: | /s/ Ronald E. Huff |
Name: Ronald E. Huff | ||
Title: Chief Financial Officer |
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