| (Mark One) |
| |X| QUARTERLY REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
| For the Quarterly Period Ended March 31, 2008 |
| or |
| |_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the transition period from __________ to __________. |
Commission File Number 001-31657
| ARENA RESOURCES, INC. | ||
| (Exact name of registrant as specified in its charter) | ||
| Nevada | 73-1596109 | |
| (State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
|
6555 S. Lewis Ave.
Tulsa, Oklahoma 74136
(Address of principal executive offices)
(918) 747-6060
(Registrant's telephone number)
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 past 12 months, and (2) has been subject to such filing requirements for the
past 90 days.
|X| Yes |_| No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act:
| Large accelerated filer |X| | Accelerated filer |_| |
| Non-accelerated filer |_| | Smaller reporting company |_| |
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act):
|_| Yes |X| No
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practical date:
As of April 30, 2008, the Company had outstanding 35,107,411 shares of common stock ($0.001 par value).
| INDEX | |||||
|---|---|---|---|---|---|
| Arena Resources, Inc. For the Quarter Ended March 31, 2008 | |||||
| Part I. Financial Information | Page | ||||
| Item 1. Financial Statements (Unaudited) | 3 | ||||
| Condensed Consolidated Balance Sheets as of March 31, 2008 and December 31, 2007 (Unaudited) |
4 | ||||
| Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2008 and 2007 (Unaudited) |
5 | ||||
| Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2008 and 2007 (Unaudited) |
6 | ||||
| Notes to Condensed Consolidated Financial Statements (Unaudited) | 7 | ||||
| Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations | 15 | ||||
| Item 3. Quantitative and Qualitative Disclosures About Market Risk | 18 | ||||
| Item 4. Controls and Procedures | 19 | ||||
| Part II. Other Information | |||||
| Item 1. Legal Proceedings | 20 | ||||
| Item 1A. Risk Factors | 20 | ||||
| Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 20 | ||||
| Item 3. Defaults Upon Senior Securities | 20 | ||||
| Item 4. Submission of Matters to a Vote of Security Holders | 20 | ||||
| Item 5. Other Information | 20 | ||||
| Item 6. Exhibits | 20 | ||||
| Signatures | 21 | ||||
The condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information 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 pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading.
In the opinion of the Company, all adjustments, consisting of only normal recurring adjustments, necessary to present fairly the consolidated financial position of the Company and the consolidated results of its operations and its cash flows have been made. The results of its operations and its cash flows for the three months ended March 31, 2008 are not necessarily indicative of the results to be expected for the year ending December 31, 2008.
ARENA RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
| March 31, 2008 |
December 31, 2007 |
||||
| ASSETS | |||||
| Current Assets | |||||
| Cash | $ | 6,687,188 | $ | 5,213,459 | |
| Accounts receivable | 23,664,455 | 20,462,160 | |||
| Joint interest billing receivable | 2,832,756 | 3,355,537 | |||
| Prepaid expenses | 29,045 | 133,393 | |||
| Total Current Assets | 33,213,444 | 29,164,549 | |||
| Property and Equipment, Using Full Cost Accounting | |||||
| Oil and gas properties subject to amortization | 380,850,166 | 339,887,859 | |||
| Drilling rigs | 6,423,897 | 6,254,737 | |||
| Land, buildings, equipment and leasehold improvements | 4,860,533 | 4,512,224 | |||
| Total Property and Equipment | 392,134,596 | 350,654,820 | |||
| Less: Accumulated depreciation and amortization | (36,796,492) | (30,497,371) | |||
| Net Property and Equipment | 355,338,104 | 320,157,449 | |||
| Total Assets | $ | 388,551,548 | $ | 349,321,998 | |
| LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
| Current Liabilities | |||||
| Accounts payable | $ | 13,399,418 | $ | 12,525,202 | |
| Income taxes payable | - | 539,793 | |||
| Fair value of oil derivative | 5,056,201 | 4,446,822 | |||
| Accrued liabilities | 2,480,044 | 1,704,658 | |||
| Total Current Liabilities | 20,935,663 | 19,216,475 | |||
| Long-Term Liabilities | |||||
| Notes payable | 40,500,000 | 35,000,000 | |||
| Asset retirement liability | 3,618,305 | 3,397,830 | |||
| Deferred income taxes | 44,429,683 | 33,896,728 | |||
| Total Long-Term Liabilities | 88,547,988 | 72,294,558 | |||
| Stockholders' Equity | |||||
| Preferred stock - $0.001 par value; 10,000,000 shares authorized; no shares issued or outstanding |
- | - | |||
| Common stock - $0.001 par value; 100,000,000 shares authorized; 35,107,411 shares and 34,278,779 shares outstanding, respectively |
35,108 | 34,279 | |||
| Additional paid-in capital | 194,173,945 | 190,852,118 | |||
| Retained earnings | 88,044,461 | 69,726,066 | |||
| Accumulated other comprehensive loss | (3,185,617) | (2,801,498) | |||
| Total Stockholders' Equity | 279,067,897 | 257,810,965 | |||
| Total Liabilities and Stockholders' Equity | $ | 388,551,548 | $ | 349,321,998 | |
See the accompanying notes to unaudited condensed consolidated financial statements.
ARENA RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
| For the Three Months Ended March 31, | 2008 | 2007 | |||||||||
| Oil and Gas Revenues | $ | 45,312,392 | $ | 16,651,301 | |||||||
| Costs and Operating Expenses | |||||||||||
| Oil and gas production costs | 2,911,925 | 2,360,949 | |||||||||
| Oil and gas production taxes | 2,329,750 | 958,651 | |||||||||
| Realized loss on oil derivatives | 1,588,440 | - | |||||||||
| Depreciation, depletion and amortization | 6,139,933 | 2,657,555 | |||||||||
| Accretion expense | 68,425 | 43,497 | |||||||||
| General and administrative expense | 2,622,983 | 1,234,786 | |||||||||
| Total Costs and Operating Expenses | 15,661,456 | 7,255,438 | |||||||||
| Other Income (Expense) | |||||||||||
| Interest income | 40,961 | 50,828 | |||||||||
| Interest expense | (615,080) | (404,167) | |||||||||
| Net Other Expense | (574,119) | (353,339) | |||||||||
| Income Before Provision for Income Taxes | 29,076,817 | 9,042,524 | |||||||||
| Provision for Deferred Income Taxes | (10,758,422) | (3,334,634) | |||||||||
| Net Income | $ | 18,318,395 | $ | 5,707,890 | |||||||
| Basic Net Income Per Common Share | 0.52 | 0.19 | |||||||||
| Diluted Net Income Per Common Share | 0.51 | 0.18 | |||||||||
| Other Comprehensive Loss | |||||||||||
| Unrealized loss on oil derivative, net of tax | (384,119) | - | |||||||||
| Total Other Comprehensive Income | $ | 17,934,276 | $ | 5,707,890 | |||||||
See the accompanying notes to unaudited condensed consolidated financial statements.
ARENA RESOURCES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
| For the Three Months Ended March 31, | 2008 | 2007 | |||
| Cash Flows From Operating Activities | |||||
| Net income | $ | 18,318,395 | $ | 5,707,890 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||
| Depreciation, depletion and amortization | 6,139,933 | 2,653,585 | |||
| Provision for income taxes | 10,758,422 | 3,334,634 | |||
| Stock based compensation | 1,760,812 | 639,624 | |||
| Accretion of asset retirement obligation | 68,425 | 43,497 | |||
| Changes in assets and liabilities: | |||||
| Accounts and joint interest receivable | (2,679,514) | 708,355 | |||
| Other changes in deferred income taxes | (540,000) | - | |||
| Prepaid expenses | 104,348 | 81,515 | |||
| Excess tax benefits from share-based payment arrangements | - | (1,714,733) | |||
| Accounts payable and accrued liabilities | 1,549,185 | (5,397,930) | |||
| Net Cash Provided by Operating Activities | 35,480,006 | 6,056,437 | |||
| Cash Flows from Investing Activities | |||||
| Purchase and development of oil and gas properties | (40,550,652) | (24,373,643) | |||
| Purchase of buildings, drilling rigs & equipment | (517,469) | (1,902,646) | |||
| Net Cash Used in Investing Activities | (41,068,121) | (26,276,289) | |||
| Cash Flows From Financing Activities | |||||
| Cash paid for offering costs | (5,000) | - | |||
| Proceeds from exercise of warrants | 38,844 | 270,003 | |||
| Proceeds from exercise of options | 1,528,000 | 485,500 | |||
| Excess tax benefits from share-based payment arrangements | - | 1,714,733 | |||
| Proceeds from issuance of notes payable | 5,500,000 | 17,200,000 | |||
| Payment of notes payable | - | (400,000) | |||
| Net Cash Provided by Financing Activities | 7,061,844 | 19,270,236 | |||
| Net Increase in Cash | 1,473,729 | (949,616) | |||
| Cash at Beginning of Period | 5,213,459 | 4,919,984 | |||
| Cash at End of Period | $ | 6,687,188 | $ | 3,970,368 | |
| Supplemental Cash Flow Information | |||||
| Cash paid for income taxes | $ | 540,000 | $ | - | |
| Cash paid for interest | 482,599 | 590,641 | |||
| Non-Cash Investing and Financing Activities | |||||
| Asset retirement obligation incurred in property development | 252,467 | 75,804 | |||
| Depreciation on drilling rigs capitalized as oil and gas properties | 159,187 | 49,922 | |||
See the accompanying notes to unaudited condensed consolidated financial statements.
Condensed Consolidated Financial Statements – The accompanying condensed consolidated financial statements have been prepared by the Company and are unaudited. In the opinion of management, the accompanying unaudited financial statements contain all adjustments necessary for fair presentation, consisting of normal recurring adjustments, except as disclosed herein.
The accompanying unaudited interim financial statements have been condensed pursuant to the rules and regulations of the Securities and Exchange Commission; therefore, certain information and disclosures generally included in financial statements have been condensed or omitted. The condensed financial statements should be read in conjunction with the Company’s annual financial statements included in its annual report on Form 10-K as of December 31, 2007. The financial position and results of operations for the three months ended March 31, 2008 are not necessarily indicative of the results to be expected for the full year ending December 31, 2008.
During 2007 the Company completed a 2 for 1 stock split, in the form of a stock dividend. Accordingly, all share amounts throughout these financial statements have been retroactively restated to account for the split.
Nature of Operations – Arena Resources, Inc. (the “Company”) owns interests in oil and gas properties located in Oklahoma, Texas, Kansas and New Mexico. The Company is engaged primarily in the acquisition, exploration and development of oil and gas properties and the production and sale of oil and gas. The accompanying statements of operations and cash flows include the operations of their wholly owned subsidiaries from the date of acquisition/formation.
Use of Estimates – The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Fair Values of Financial Instruments – The carrying amounts reported in the balance sheets for accounts receivable, joint interest billings receivable, accounts payable, and accrued liabilities approximate fair value because of the immediate or short-term maturity of these financial instruments. The carrying amounts reported for notes payable and long-term debt approximate fair value because the underlying instruments are at interest rates which approximate current market rates. The fair value estimates for oil derivatives are derived from published market prices for the underlying commodities to determine discounted expected future cash flows as of the date of the estimate. See Note 9—Derivative Instruments.
Consolidation – The accompanying consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.
Concentration of Credit Risk and Major Customer – The Company has cash in excess of federally insured limits at March 31, 2008. During the three months ended March 31, 2008, sales to one customer represented 83% of oil and gas revenues. At March 31, 2008, this customer made up 86% of accounts receivable.
Oil and Gas Properties – The Company uses the full cost method of accounting for oil and gas properties. Under this method, all costs associated with acquisition, exploration, and development of oil and gas reserves are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. Capitalized costs are categorized either as being subject to amortization or not subject to amortization.
All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves and estimated future costs of abandonment and site restoration, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent engineers. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined. The Company evaluates oil and gas properties for impairment at least annually. Amortization expense for the three months ended March 31, 2008 was $6,139,933, based on depletion at the rate of $11.78 per barrel of oil equivalent compared to $2,657,555, based on depletion at the rate of $7.89 per barrel of oil equivalent for the three months ended March 31, 2007. These amounts include $49,691 and $8,437 of depreciation for the three months ended March 31, 2008 and 2007, respectively.
In addition, capitalized costs are subject to a ceiling test which limits such costs to the estimated present value of future net revenues from proved reserves, discounted at a 10-percent interest rate, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties. Consideration received from sales or transfers of oil and gas property is accounted for as a reduction of capitalized costs. Revenue is not recognized in connection with contractual services performed on properties in which the Company holds an ownership interest.
Drilling Rigs – Drilling rigs are valued at historical cost adjusted for impairment loss less accumulated depreciation. Historical costs include all direct costs associated with the acquisition of drilling rigs and placing them in service. Drilling rigs are depreciated over 10 years and the depreciation is capitalized as part of oil and gas properties subject to amortization. For the three months ended March 31, 2008 and 2007 the Company had depreciation of $159,187 and $49,922, respectively, on the Company owned drilling rigs.
Land, Buildings, Equipment and Leasehold Improvements – Land, buildings, equipment and leasehold improvements are valued at historical cost adjusted for impairment loss less accumulated depreciation. Historical costs include all direct costs associated with the acquisition of land, buildings, equipment and leasehold improvements and placing them in service.
Depreciation of buildings and equipment is calculated using the straight-line method based upon the following estimated useful lives:
| Buildings and improvements | 30 years |
| Office equipment and software | 5-7 years |
| Machinery and equipment | 5-7 years |
One building has not been placed in service and, therefore, the Company has not recorded any depreciation on this building. Depreciation expense on the buildings and improvements was $29,152 for the three months ended March 31, 2008. No depreciation was taken during the three months ended March 31, 2007 on buildings and improvement, as there were no Company owned buildings during that time period. An aggregate value of $530,000 has been attributed to the land on which the buildings are located and is not depreciated.
Basic and Diluted Income Per Common Share – Basic income per common share is computed by dividing net income by the weighted-average number of common shares outstanding during the period. Diluted income per share reflects the potential dilution that could occur if all contracts to issue common stock were converted into common stock, except for those that are anti-dilutive. The dilutive effect of stock options and other share based compensation is calculated using the treasury method with an offset from expected proceeds upon exercise of the stock options and unrecognized compensation expense.
Recent Accounting Pronouncements – In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment to FASB Statement No. 115 (“SFAS 159”). SFAS 159 allows companies to choose to measure eligible assets and liabilities at fair value with changes in value recognized in earnings. Fair value treatment for eligible assets and liabilities may be elected either prospectively upon initial recognition, or if an event triggers a new basis of accounting for an existing asset or liability. The Company adopted SFAS 159 on January 1, 2008. The adoption of SFAS 159 had no material impact on its financial position and results of operations as the Company has not elected to utilize the fair value option on any assets or liabilities.
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133, which changes the disclosure requirements for derivative instruments and hedging activities. Enhanced disclosures are required to provide information about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. This Statement will require the additional disclosures described above. The Company is does not expect the adoption of SFAS 161 to have a material impact on its results of operations or financial condition.
In December 2007, the FASB issued Statements of Financial Accounting Standards No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”) and No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment to ARB No. 51” (“SFAS 160”). Both SFAS 141R and SFAS 160 are to be adopted effective January 1, 2009. SFAS 141R requires the application of several new or modified accounting concepts that, due to their complexity, could introduce a degree of volatility in periods subsequent to a material business combination. SFAS 141R requires that all business combinations result in assets and liabilities acquired being recorded at their fair value, with limited exceptions. Other areas related to business combinations that will require changes from current GAAP include: contingent consideration, acquisition costs, contingencies, restructuring costs, in process research and development and income taxes, among others. SFAS 160 will primarily impact the presentation of minority or noncontrolling interests within the Balance Sheet and Statement of Operations as well as the accounting for transactions with noncontrolling interest holders. The Company does not expect the adoption of SFAS 141R or 160 to have a material impact on its results of operations or financial condition.
| For the Three Months Ended March 31, | 2008 | 2007 | |||||||||
| Net Income | $ | 18,318,395 | $ | 5,707,890 | |||||||
| Basic Weighted-Average Common Shares Outstanding | 34,892,570 | 29,512,394 | |||||||||
| Effect of dilutive securities | |||||||||||
| Warrants | 228,232 | 411,932 | |||||||||
| Stock options | 1,108,624 | 1,331,946 | |||||||||
| Diluted Weighted-Average Common Shares Outstanding | 36,229,426 | 31,256,272 | |||||||||
| Basic Income Per Common Share | |||||||||||
| Net income | 0.52 | 0.19 | |||||||||
| Diluted Income Per Common Share | |||||||||||
| Net income | 0.51 | 0.18 | |||||||||
For the three months ended March 31, 2008, 525,000 stock options were not included in the computation of diluted income per share as their effects are anti-dilutive.
Acquisition of Oil and Gas Properties – On December 11, 2007, the Company consummated a transaction pursuant to which the Company acquired a 100% working interest, 75% net revenue interest, in the South Fuhrman Mascho Unit, a 100% working interest, 78.125% net revenue interest, in the University Consolidated IX Unit and a 100% working interest, 75% net revenue interest, in approximately 5,040 acres of undeveloped acreage (collectively, the “Properties”), all of which are located in Andrews County, Texas. The Properties were acquired from Phoenix PetroCorp, Inc. The effective date of the acquisition was December 1, 2007. The Company acquired the Properties for their current production, as well as for the approximately 120 additional drilling locations which we estimate exist on the Properties. The Company paid $49,000,000 to the sellers. In addition, the Company paid acquisition costs of $222,250, including the issuance of 5,000 shares of common stock as a consulting and finder’s fee, valued at $204,750, or $40.95 per share. The acquisition was funded through the use of cash on hand and proceeds from the Company’s credit facility.
The following unaudited pro forma information is presented to reflect the operations of the Company as if the acquisitions of the properties had been completed on January 1, 2007:
| For the Three Months Ended March 31, | 2008 | 2007 | |||||||||
| Oil and Gas Revenues | $ | 45,312,392 | $ | 17,090,595 | |||||||
| Net Income | 18,318,395 | 5,208,603 | |||||||||
| Income Per Common Share | |||||||||||
| Basic Net Income Per Common Share | $ | 0.52 | $ | 0.16 | |||||||
| Diluted Net Income Per Common Share | 0.51 | 0.15 | |||||||||
Credit facility – In June 2007, the Company entered into a new agreement that increased the borrowing base under its credit facility to $100,000,000, while leaving the credit facility at $150,000,000. Additionally, the interest rate was changed to be a floating rate equal to the 30, 60 or 90 day LIBOR rate plus 1.75%. Additionally, the subordination of the loans from two officers was released. All other terms and conditions remained the same. As of March 31, 2008, the Company was in compliance with all covenants and had $40,500,000 outstanding under this credit facility.
The Company provides for the obligation to plug and abandon oil and gas wells at the dates properties are either acquired or the wells are drilled. The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The reconciliation of the asset retirement obligation for the three months ended March 31, 2008 is as follows:
| Balance, January 1, 2008 | $ | 3,397,830 | |||
| Liabilities incurred | 252,467 | ||||
| Accretion expense | 68,425 | ||||
| Liabilities settled | (100,417) | ||||
| Balance, March 31, 2008 | $ | 3,618,305 | |||
Warrants exercised – During the three months ended March 31, 2008, the Company issued 8,632 shares of common stock from the exercise of warrants with an exercise price of $4.50 per share, for proceeds of $38,844.
Options exercised – During the three months ended March 31, 2008, the Company issued 820,000 shares of common stock from the exercise of options for proceeds of $1,528,000. Of these options, 800,000 had an exercise price of $1.85 per share and 20,000 had an exercise price of $2.40 per share.
Compensation expense charged against income for stock based awards during the three months ended March 31, 2008 was $1,760,812, as compared to $639,624 for the three months ended March 31, 2007, and is included in general and administrative expense in the accompanying financial statements.
The Company did not grant any nonqualified stock options to directors and employees during the three months ended March 31, 2008. A summary of the status of the stock options as of March 31, 2008 and changes during the three months ended March 31, 2008 is as follows:
| Options | Weighted-Average Exercise Price | ||||||||||
| Outstanding at December 31, 2007 | 3,450,000 | $ | 13.55 | ||||||||
| Exercised | (820,000) | 1.86 | |||||||||
| Outstanding at March 31, 2008 | 2,630,000 | 17.19 | |||||||||
| Exercisable at March 31, 2008 | 495,000 | $ | 8.32 | ||||||||
As of March 31, 2008, there was approximately $11,642,928 of unrecognized compensation cost related to stock options that will be recognized over a weighted average period of 2.72 years. The aggregate intrinsic value of options expected to vest at March 31, 2008 was $42,558,601. The aggregate intrinsic value of options exercisable at March 31, 2008 was $19,161,450. The intrinsic value is based on a March 31, 2008 closing price of the Company’s common stock of $38.71.
The 820,000 options exercised during the three months ended March 31, 2008 had an intrinsic value of $10,329,700 on the date of exercise. Any excess tax benefits from the vesting of restricted stock and the exercise of stock options will not be recognized in paid-in capital until the Company is in a current tax paying position. Presently, all of the Company’s income taxes are deferred and the Company has substantial net operating losses available to carryover to future periods. Accordingly, no excess tax benefits have been recognized for the three months ended March 31, 2008.
Standby Letters of Credit – A commercial bank has issued standby letters of credit on behalf of the Company to the states of Texas, Oklahoma, New Mexico and Kansas totaling $660,432 to allow the Company to do business in those states. The standby letters of credit are valid until cancelled or matured and are collateralized by the revolving credit facility with the bank. Letter of credit terms range from one to five years. The Company intends to renew the standby letters of credit for as long as the Company does business in those states. No amounts have been drawn under the standby letters of credit.
In 2007 the Company entered into a derivative contract in order to manage the commodity price risk for a portion of production through 2008. The Company’s current derivative contract is a costless collar. A collar is a contract which combines both a put option or “floor” and a call option or “ceiling.” The Company receives the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pays the excess, if any, of the reference price over the ceiling price. The following is information relating to the Company’s collar position as of March 31, 2008.
| Commodity | Period | Volume | Floor | Ceiling |
|---|---|---|---|---|
| WTI Crude Oil | August 2007 - December 2008 | 458,000 | $ 65.00 | $ 80.50 |
The changes in fair value of the oil hedging contracts in place at March 31, 2008, resulted in an increase in the liability of $609,379, to $5,056,201. The after tax impact of the change in the fair value of the hedge of $384,119 is reflected in other comprehensive income. Changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value from ineffectiveness is recognized currently in unrealized derivative gain or loss in the consolidated statements of operations.
Cash settlements of cash flow hedges are recorded as a loss on derivatives in the operating section of the Company’s statement of operations. Our statement of operations for the three months ended March 31, 2008 includes a loss on derivative instrument of $1,558,440. No amounts were shown for the three months ended March 31, 2007 because the Company did not have any hedging contracts in place at that time.
SFAS No. 157, “Fair Value Measurements” (SFAS 157), establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, provides guidance on the methods used to estimate fair value and expands disclosures about fair value measurements. On January 1, 2008, the Company applied SFAS 157 for its assets and liabilities that are measured at fair value on a recurring basis, primarily our costless collars. The initial adoption of SFAS 157 had no material impact on the Company’s Consolidated Financial Statements. In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-2, permitting entities to delay application of SFAS 157 to fiscal years beginning after November 15, 2008, for non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Beginning January 1, 2009, the Company will apply SFAS 157 fair value requirements to non-financial assets and non-financial liabilities that are not recognized or disclosed on a recurring basis. SFAS 157 requires two distinct transition approaches: (1) cumulative-effect adjustment to beginning retained earnings for certain financial instrument transactions and (2) prospectively as of the date of adoption through earnings or other comprehensive income, as applicable for all other instruments. Upon adopting SFAS 157, the Company applied a prospective transition as it did not have financial instrument transactions that required a cumulative-effect adjustment to beginning retained earnings.
Fair value is the price that would be received to sell an asset or the amount paid to transfer a liability in an orderly transaction between market participants (an exit price) at the measurement date. Fair value is a market based measurement considered from the perspective of a market participant. The Company uses market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation. These inputs can be readily observable, market corroborated, or unobservable. The Company primarily applies a market approach for recurring fair value measurements using the best available information while utilizing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The Company’s fair value balances are based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
| • | Level 1 — Quoted prices in active markets for identical assets or liabilities that the Company has the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company does not have any fair value balances classified as Level 1. |
| • | Level 2 — Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. The Company’s Level 2 items consist of a costless collars. |
| • | Level 3 — Includes inputs that are not observable for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. Level 3 would include instruments valued using industry standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall fair value. The Company does not have any fair value balances classified as Level 3. |
In valuing certain contracts, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. For disclosure purposes, assets and liabilities are classified in their entirety in the fair value hierarchy level based on the lowest level of input that is significant to the overall fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels.
The following table sets forth by level within the fair value hierarchy the Company’s liabilities that are measured at fair value on a recurring basis:
| Fair Value Measurements at March 31, 2008 Using: | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Quoted Prices in Active Markets for Identical Liabilities: (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
Total | ||||||||
| Liabilities: | |||||||||||
| Costless collars | $ | - | $ | 5,056,201 | $ | - | $ | 5,056,201 | |||
Subsequent to March 31, 2008, the Company has drawn $5,500,000 on its credit facility.
Results of Operations – For the Three Months Ended March 31, 2008
Oil and natural gas sales. For the three months ended March 31, 2008, oil and natural gas sales revenue increased $28,661,091 to $45,312,392, compared to $16,651,301 for the same period during 2007. Oil sales increased $27,115,670 and natural gas sales increased $1,545,421. The increases were the result of our increased volumes due to our development and increased oil and gas prices between periods. For the three months ended March 31, 2008, oil sales volume increased 170,518 barrels to 453,056 barrels, compared to 282,538 barrels for the same period in 2007. The average realized per barrel oil price increased 78% from $51.71 for the three months ended March 31, 2007 to $92.10 for the three months ended March 31, 2008. For the three months ended March 31, 2008, gas sales volume increased 58,979 thousand cubic feet (MCF) to 383,914 MCF, compared to 324,935 MCF for the same period in 2007. The average realized natural gas price per MCF increased 49% from $6.28 for the three months ended March 31, 2007 to $9.34 for the three months ended March 31, 2008.
Oil and gas production costs. Our lease operating expenses (LOE) increased from $2,360,949 or $7.01 per barrel of oil equivalent (BOE) for the three months ended March 31, 2007 to $2,911,925 or $5.63 per BOE for the three months ended March 31, 2008. The increase in total LOE was due to our on-going development projects. The decrease in the per BOE amounts is a result of increased production as a result of the development of our properties.
Production taxes. Production taxes as a percentage of oil and natural gas sales were 6% during the three months ended March 31, 2007 and decreased to 5% for the three months ended March 31, 2008. Production taxes vary from state to state. Therefore, these taxes may vary in the future depending on the mix of production we generate from various states, as well as the possibility that any state may raise its production tax rate.
Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased by $3,482,378 to $6,139,933 for the three months ended March 31, 2008, compared to the same period in 2007. The increase was primarily a result of an increase in volume and in the average depletion rate from $7.89 per BOE during the three months ended March 31, 2007 to $11.78 per BOE during the three months ended March 31, 2008. The increased depletion rate was the result of increased capitalized costs and development costs.
General and administrative expenses. General and administrative expenses increased by $1,388,197 to $2,622,983 for the three months ended March 31, 2008, compared to the same period in 2007. A portion of this increase was due to the increase of stock-based compensation expense of $1,760,812 as compared to $639,624 for the same period in 2007. The remaining increase was primarily related to increases in compensation expense associated with an increase in personnel required to administer our growth.
Interest income. Interest income was $40,961 for the three months ended March 31, 2008, compared to $50,828 for the three months ended March 31, 2007. The decrease was due to lower cash balances between periods.
Interest expense. Interest expense was $615,080 for the three months ended March 31, 2008, compared to $404,167 for the three months ended March 31, 2007. The increase was due to larger outstanding debt between the periods.
Income tax expense. Our effective tax rate was 37% during the three months ended March 31, 2007 and remained steady at 37% for the three months ended March 31, 2008.
Net income. Net income increased from $5,707,890 for the three months ended March 31, 2007 to $18,318,395 for the same period in 2008. The primary reasons for this increase include increased volumes as a result of the development of our properties and higher commodity prices between periods, partially offset by higher lease operating expense, general and administrative expense and income tax expense due to our growth.
Revenues Year to Date by Geographic section
Arena reports its net oil and gas revenues for the year to date as applicable to the following geographic sectors:
| Net Production Volume | Net Revenue | |||
| Texas Leases | 390,062 | BBLS | $ | 35,879,467 |
| Oklahoma Leases | 9,923 | BBLS | $ | 935,850 |
| New Mexico Leases | 53,071 | BBLS | $ | 4,910,289 |
| Net Production Volume | Net Revenue | |||
| Texas Leases | 262,450 | MCF | $ | 2,568,454 |
| Oklahoma Leases | 6,240 | MCF | $ | 39,677 |
| New Mexico Leases | 71,860 | MCF | $ | 776,285 |
| Kansas Leases | 43,364 | MCF | $ | 202,370 |
Significant Subsequent Events occurring after March 31, 2008:
Subsequent to March 31, 2008, the Company has drawn $5,500,000 on its credit facility.
Capital Resources and Liquidity
As shown in the financial statements for the three months ended March 31, 2008, the Company had cash on hand of $6,687,188, compared to $5,213,459 as of December 31, 2007. The Company had net cash provided by operating activities for the three months ended March 31, 2008 of $35,480,006, compared to $6,056,437 for the same period 2007. Other significant sources of cash inflow were $5,500,000 drawn down on the Company’s credit facility and proceeds from option and warrant exercises of $1,566,844 in 2008 and $17,200,000 drawn down on the Company’s credit facility and proceeds from option and warrant exercises of $755,503 in 2007. The most significant cash outflows during the three months ended March 31, 2008 and 2007 were capital expenditures of $41,068,121 in 2008 and $26,276,289 in 2007 and repayment of notes payable to related parties of $400,000 in 2007.
In June 2007, the Company entered into a new agreement that increased the borrowing base under its credit facility to $100,000,000, while leaving the credit facility at $150,000,000. Additionally, the interest rate was changed to be a floating rate equal to the 30, 60 or 90 day LIBOR rate plus 1.75%. Additionally, the subordination of the loans from two officers was released. All other terms and conditions remained the same. As of March 31, 2008, the Company was in compliance with all covenants and had $40,500,000 outstanding under this credit facility.
Disclosures About Market Risks
Like other natural resource producers, Arena faces certain unique market risks. The two most salient risk factors are the volatile prices of oil and gas and certain environmental concerns and obligations.
Oil and Gas Prices
Current competitive factors in the domestic oil and gas industry are unique. The actual price range of crude oil is largely established by major international producers. Pricing for natural gas is more regional. Because domestic demand for oil and gas exceeds supply, there is little risk that all current production will not be sold at relatively fixed prices. To this extent Arena does not see itself as directly competitive with other producers, nor is there any significant risk that the Company could not sell all production at current prices with a reasonable profit margin. The risk of domestic overproduction at current prices is not deemed significant. The primary competitive risks would come from falling international prices which could render current production uneconomical.
Secondarily, Arena is presently committed to use the services of the existing gatherers in its present areas of production. This gives to such gatherers certain short term relative monopolistic powers to set gathering and transportation costs, because obtaining the services of an alternative gathering company would require substantial additional costs since an alternative gatherer would be required to lay new pipeline and/or obtain new rights-of-way in the lease.
It is also significant that more favorable prices can usually be negotiated for larger quantities of oil and/or gas product, such that Arena views itself as having a price disadvantage to larger producers. Large producers also have a competitive advantage to the extent they can devote substantially more resources to acquiring prime leases and resources to better find and develop prospects.
Environmental
Oil and gas production is a highly regulated activity which is subject to significant environmental and conservation regulations both on a federal and state level. Historically, most of the environmental regulation of oil and gas production has been left to state regulatory boards or agencies in those jurisdictions where there is significant gas and oil production, with limited direct regulation by such federal agencies as the Environmental Protection Agency. However, while the Company believes this generally to be the case for its production activities in Texas, Oklahoma, Kansas and New Mexico, it should be noticed that there are various Environmental Protection Agency regulations which would govern significant spills, blow-outs, or uncontrolled emissions.
In Oklahoma, Texas, Kansas and New Mexico specific oil and gas regulations exist related to the drilling, completion and operations of wells, as well as disposal of waste oil. There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the Oklahoma Corporation Commission, Oil and Gas Division, the Texas Railroad Commission, Oil and Gas Division, the Kansas Corporation Commission, Oil and Gas Division or the New Mexico Oil Conservation Division.
Compliance with these regulations may constitute a significant cost and effort for Arena. No specific accounting for environmental compliance has been maintained or projected by Arena to date. Arena does not presently know of any environmental demands, claims, or adverse actions, litigation or administrative proceedings in which it or the acquired properties are involved or subject to or arising out of its predecessor operations.
In the event of a breach of environmental regulations, these environmental regulatory agencies have a broad range of alternative or cumulative remedies to include: ordering a cleanup of any spills or waste material and restoration of the soil or water to conditions existing prior to the environmental violation; fines; or enjoining further drilling, completion or production activities. In certain egregious situations the agencies may also pursue criminal remedies against the Company or its principals.
Forward-Looking Information
Certain statements in this Section and elsewhere in this report are forward-looking in nature and relate to trends and events that may affect the Company’s future financial position and operating results. Such statements are made pursuant to the safe harbor provision of the Private Securities Litigation Reform Act of 1995. The terms “expect,” “anticipate,” “intend,” and “project” and similar words or expressions are intended to identify forward-looking statements. These statements speak only as of the date of this report. The statements are based on current expectations, are inherently uncertain, are subject to risks, and should be viewed with caution. Actual results and experience may differ materially from the forward-looking statements as a result of many factors, including changes in economic conditions in the markets served by the company, increasing competition, fluctuations in raw materials and energy prices, and other unanticipated events and conditions. It is not possible to foresee or identify all such factors. The company makes no commitment to update any forward-looking statement or to disclose any facts, events, or circumstances after the date hereof that may affect the accuracy of any forward-looking statement.
Interest Rate Risk
The Company is subject to interest rate risk on its revolving credit facility, which bears variable interest based upon a LIBOR rate. Changes in interest rates affect the interest earned on the Company’s cash and cash equivalents and the interest rate paid on borrowings under its bank credit facility. Currently, the Company does not use interest rate derivative instruments to manage exposure to interest rate changes.
Commodity Price Risk
The Company’s revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and Arena’s ability to borrow and raise additional capital. The amount the Company can borrow under its bank credit facility is subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that the Company can economically produce. Arena currently sells all of its oil and natural gas production under price sensitive or market price contracts.
In 2007 the Company entered into a derivative contract in order to manage the commodity price risk for a portion of its production through 2008. The Company’s current derivative contract is a costless collar. A collar is a contract which combines both a put option or “floor” and a call option or “ceiling.” The Company receives the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pays the excess, if any, of the reference price over the ceiling price. The following is information relating to the Company’s collar position as of March 31, 2008.
| Commodity | Period | Volume | Floor | Ceiling |
|---|---|---|---|---|
| WTI Crude Oil | August 2007 - December 2008 | 458,000 | $ 65.00 | $ 80.50 |
The changes in fair value of the oil hedging contracts in place at March 31, 2008, resulted in an increase in the liability of $609,379. The after tax impact of the change in the fair value of the hedge of $384,119 is reflected in other comprehensive income. Changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value from ineffectiveness is recognized currently in unrealized derivative gain or loss in the consolidated statements of operations.
Cash settlements of cash flow hedges are recorded as a loss on derivatives in the operating section of the Company’s statement of operations. Our statement of operations for the three months ended March 31, 2008 includes a loss on derivative instrument of $1,558,440. No amounts were shown for the three months ended March 31, 2007 because the Company did not have any hedging contracts in place at that time.
Additionally, to the extent we hedge our commodity price exposure, we will forego the benefits we would have otherwise experienced if commodity prices were to change in our favor.
Currency Exchange Rate Risk
Foreign sales accounted for none of the Company’s sales; further, the Company accepts payment for its commodity sales only in U.S. dollars; hence, Arena is not exposed to foreign currency exchange rate risk on these sales.
Evaluation of Disclosure Controls and Procedures
The Company maintains controls and procedures designed to ensure that information required to be disclosed by the Company in the reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. At the end of the period covered by this Quarterly Report on Form 10-Q, the Company’s management, under the supervision and with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based on that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that as of the end of such period the Company’s disclosure control and procedures are effective in alerting them to material information that is required to be included in the reports the Company files or submits under the Securities Exchange Act of 1934.
Changes in Internal Controls Over Financial Reporting
There have been no changes in the Company’s internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
None.
There have been no material changes from risk factors as previously disclosed in our Form 10-K in response to Item 1A to Part I of Form 10-K.
None.
None.
None.
None.
| (a) | Section 302 Certification of CEO |
Section 302 Certification of CFO |
| (b) | Section 1350 Certification of CEO |
Section 1350 Certification of CFO |
Pursuant to the requirements of the Securities Exchange Act of 1934, Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| REGISTRANT: ARENA RESOURCES, INC. | |
| Dated: May 7, 2008 | By: /s/ Lloyd Tim Rochford |
| Lloyd Tim Rochford | |
| Chief Executive Officer |
| Dated: May 7, 2008 | By: /s/ Phillip W. Terry |
| Phillip W. Terry | |
| President |
| Dated: May 7, 2008 | By: /s/ William R. Broaddrick |
| William R. Broaddrick | |
| Vice President, Chief Financial Officer |