UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
| (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, 2009 |
| 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 27, 2009, the Company had outstanding 38,210,187 shares of common stock ($0.001 par value).
| INDEX | |||||
|---|---|---|---|---|---|
| Arena Resources, Inc. For the Quarter Ended March 31, 2009 | |||||
| Part I. Financial Information | Page | ||||
| Item 1. Financial Statements (Unaudited) | 3 | ||||
| Condensed Consolidated Balance Sheets as of March 31, 2009 and December 31, 2008 (Unaudited) |
4 | ||||
| Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2009 and 2008 (Unaudited) |
5 | ||||
| Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2009 and 2008 (Unaudited) |
6 | ||||
| Notes to Condensed Consolidated Financial Statements (Unaudited) | 7 | ||||
| Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations | 16 | ||||
| Item 3. Quantitative and Qualitative Disclosures About Market Risk | 19 | ||||
| Item 4. Controls and Procedures | 20 | ||||
| Part II. Other Information | |||||
| Item 1. Legal Proceedings | 21 | ||||
| Item 1A. Risk Factors | 21 | ||||
| Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 21 | ||||
| Item 3. Defaults Upon Senior Securities | 21 | ||||
| Item 4. Submission of Matters to a Vote of Security Holders | 21 | ||||
| Item 5. Other Information | 21 | ||||
| Item 6. Exhibits | 21 | ||||
| Signatures | 22 | ||||
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, 2009 are not necessarily indicative of the results to be expected for the year ending December 31, 2009.
ARENA RESOURCES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
| March 31, 2009 |
December 31, 2008 |
||||
| ASSETS | |||||
| Current Assets | |||||
| Cash | $ | 52,403,274 | $ | 58,489,574 | |
| Accounts receivable | 7,723,854 | 8,637,308 | |||
| Joint interest billing receivable | 2,794,860 | 2,836,948 | |||
| Receivable from oil derivative | 1,610,078 | 2,508,396 | |||
| Fair value of oil derivative | 11,597,203 | 16,210,478 | |||
| Prepaid expenses | 699,043 | 847,433 | |||
| Total Current Assets | 76,828,312 | 89,530,137 | |||
| Property and Equipment | |||||
| Oil and gas properties subject to amortization | 565,702,229 | 548,714,235 | |||
| Inventory for property development | 2,002,021 | 1,670,067 | |||
| Drilling rigs | 7,142,008 | 6,899,433 | |||
| Land, buildings, equipment and leasehold improvements | 5,799,045 | 5,799,045 | |||
| Total Property and Equipment | 580,645,303 | 563,082,780 | |||
| Less: Accumulated depreciation and amortization | (68,270,298) | (60,928,142) | |||
| Net Property and Equipment | 512,375,005 | 502,154,638 | |||
| Total Assets | $ | 589,203,317 | $ | 591,684,775 | |
| LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
| Current Liabilities | |||||
| Accounts payable | $ | 2,875,823 | $ | 12,877,084 | |
| Deferred income taxes | 4,290,965 | 6,046,508 | |||
| Accrued liabilities | 1,176,174 | 865,955 | |||
| Total Current Liabilities | 8,342,962 | 19,789,547 | |||
| Long-Term Liabilities | |||||
| Asset retirement liability | 5,295,330 | 5,066,348 | |||
| Deferred income taxes | 88,381,161 | 84,533,419 | |||
| Total Long-Term Liabilities | 93,676,491 | 89,599,767 | |||
| 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; 38,210,187 shares and 38,210,187 shares outstanding, respectively |
38,210 | 38,210 | |||
| Additional paid-in capital | 320,030,700 | 318,701,383 | |||
| Retained earnings | 159,808,716 | 153,343,267 | |||
| Accumulated other comprehensive income | 7,306,238 | 10,212,601 | |||
| Total Stockholders' Equity | 487,183,864 | 482,295,461 | |||
| Total Liabilities and Stockholders' Equity | $ | 589,203,317 | $ | 591,684,775 | |
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, | 2009 | 2008 | |||||||||
| Oil and Gas Revenues | $ | 20,193,160 | $ | 45,312,392 | |||||||
| Costs and Operating Expenses | |||||||||||
| Oil and gas production costs | 4,206,783 | 2,911,925 | |||||||||
| Oil and gas production taxes | 1,098,339 | 2,329,750 | |||||||||
| Realized loss (gain) on oil derivatives | (5,111,210) | 1,588,440 | |||||||||
| Depreciation, depletion and amortization | 7,231,481 | 6,139,933 | |||||||||
| Accretion expense | 94,750 | 68,425 | |||||||||
| General and administrative expense | 2,674,769 | 2,622,983 | |||||||||
| Total Costs and Operating Expenses | 10,194,912 | 15,661,456 | |||||||||
| Other Income (Expense) | |||||||||||
| Interest income | 266,312 | 40,961 | |||||||||
| Interest expense | - | (615,080) | |||||||||
| Net Other Income (Expense) | 266,312 | (574,119) | |||||||||
| Income Before Provision for Income Taxes | 10,264,560 | 29,076,817 | |||||||||
| Provision for Deferred Income Taxes | (3,799,111) | (10,758,422) | |||||||||
| Net Income | $ | 6,465,449 | $ | 18,318,395 | |||||||
| Basic Net Income Per Common Share | 0.17 | 0.52 | |||||||||
| Diluted Net Income Per Common Share | 0.17 | 0.51 | |||||||||
| Other Comprehensive Income (Loss) | |||||||||||
| Realized loss (gain) on hedge derivative contract settlements reclassified from other comprehensive (loss) income |
(2,916,308) | 855,190 | |||||||||
| Change in unrealized deferred hedging gains (losses) | 9,945 | (1,239,309) | |||||||||
| Total Other Comprehensive Income | $ | 3,559,086 | $ | 17,934,276 | |||||||
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, | 2009 | 2008 | |||
| Cash Flows From Operating Activities | |||||
| Net income | $ | 6,465,449 | $ | 18,318,395 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||
| Depreciation, depletion and amortization | 7,231,481 | 6,139,933 | |||
| Provision for income taxes | 3,799,111 | 10,758,422 | |||
| Stock based compensation | 1,329,317 | 1,760,812 | |||
| Accretion of asset retirement obligation | 94,750 | 68,425 | |||
| Changes in assets and liabilities: | |||||
| Accounts and joint interest receivable | 1,853,860 | (2,679,514) | |||
| Other changes in deferred income taxes | - | (540,000) | |||
| Prepaid expenses | 148,390 | 104,348 | |||
| Accounts payable and accrued liabilities | (9,691,042) | 1,549,185 | |||
| Net Cash Provided by Operating Activities | 11,231,316 | 35,480,006 | |||
| Cash Flows from Investing Activities | |||||
| Purchase and development of oil and gas properties | (15,256,515) | (40,550,652) | |||
| Purchase of inventory for property development | (1,818,526) | - | |||
| Purchase of buildings, drilling rigs & equipment | (242,575) | (517,469) | |||
| Net Cash Used in Investing Activities | (17,317,616) | (41,068,121) | |||
| Cash Flows From Financing Activities | |||||
| Cash paid for offering costs | - | (5,000) | |||
| Proceeds from exercise of warrants | - | 38,844 | |||
| Proceeds from exercise of options | - | 1,528,000 | |||
| Proceeds from issuance of notes payable | - | 5,500,000 | |||
| Net Cash Provided by Financing Activities | - | 7,061,844 | |||
| Net Increase (Decrease) in Cash | (6,086,300) | 1,473,729 | |||
| Cash at Beginning of Period | 58,489,574 | 5,213,459 | |||
| Cash at End of Period | $ | 52,403,274 | $ | 6,687,188 | |
| Supplemental Cash Flow Information | |||||
| Cash paid for income taxes | $ | - | $ | 540,000 | |
| Cash paid for interest | - | 482,599 | |||
| Non-Cash Investing and Financing Activities | |||||
| Asset retirement obligation incurred in property development | 134,232 | 252,467 | |||
| Depreciation on drilling rigs capitalized as oil and gas properties | 110,675 | 159,187 | |||
| Use of inventory in property development | 1,486,572 | - | |||
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, 2008. The financial position and results of operations for the three months ended March 31, 2009 are not necessarily indicative of the results to be expected for the full year ending December 31, 2009.
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.
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, 2009. During the three months ended March 31, 2009, sales to two customers represented 77% and 10%, respectively, of oil and gas revenues. At March 31, 2009, these customers made up 80% and 9%, respectively, 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, 2009 was $7,231,481, based on depletion at the rate of $12.60 per barrel of oil equivalent compared to $6,139,933, based on depletion at the rate of $11.78 per barrel of oil equivalent for the three months ended March 31, 2008. These amounts include $73,274 and $49,691 of depreciation for the three months ended March 31, 2009 and 2008, 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, 2009 and 2008 the Company had depreciation of $110,675 and $159,187, respectively, on the Company owned drilling rigs. During the three months ended March 31, 2009, the Company discontinued use of one of the two Company owned rigs and prepared it for storage. Because the rig was not in use during the quarter no depreciation was calculated on that rig. Once it is placed back in service depreciation will again be accounted for on it. The rig will remain idle until commodity prices increase to make it economical to begin using it again.
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 |
Depreciation expense on the buildings and improvements for the three months ended March 31, 2009 and 2008 was $38,992 and $29,152, respectively. An aggregate value of $530,000 has been attributed to the land on which the buildings are located and is not depreciated.
Inventory for Property Development – Inventories consist primarily of tubular goods used in our development and are stated at the lower of specific cost of each inventory item or market value.
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 December 2008, the SEC announced that it had approved revisions to its oil and gas reporting disclosures. The new disclosure requirements include provisions that:
| • | Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations. |
| • | Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end prices. The SEC indicated that they will continue to communicate with the FASB staff to align their accounting standards with these rules. The FASB currently requires a single-day, year-end price for accounting purposes. |
| • | Permit companies to disclose their probable and possible reserves on a voluntary basis. In the past, proved reserves were the only reserves allowed in the disclosures. |
| • | Requires companies to provide additional disclosure regarding the aging of proved undeveloped reserves. |
| • | Permit the use of reliable technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. |
| • | Replace the existing “certainty” test for areas beyond one offsetting drilling unit from a productive well with a “reasonable certainty” test. |
| • | Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures regarding internal controls over reserve estimation, as well as a report addressing the independence and qualifications of its reserves preparer or auditor will be mandatory. |
We will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. We are currently in the process of evaluating the new requirements.
In April 2009, the FASB issued FSP FAS 107-1 and Accounting Principles Board (“APB”) Opinion No. 28-1 (collectively, “FSP FAS 107-1”), “Interim Disclosures about Fair Value of Financial Instruments.” FSP FAS 107-1 amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” to require an entity to provide disclosures about fair value of financial instruments in interim financial information. The FSP FAS 107-1 also amends APB Opinion No. 28, “Interim Financial Reporting,” to require those disclosures about the fair value of financial instruments in summarized financial information at interim reporting periods. Under FSP FAS 107-1, the Company will be required to include disclosures about the fair value of its financial instruments whenever it issues financial information for interim reporting periods. In addition, the Company will be required to disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods, the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. FSP FAS 107-1 is effective for periods ending after June 15, 2009 and its adoption is expected to have no impact on the Company’s results of operations and financial condition but will require additional disclosures about the fair value of financial instruments in its financial statements
| For the Three Months Ended March 31, | 2009 | 2008 | |||||||||
| Net Income | $ | 6,465,449 | $ | 18,318,395 | |||||||
| Basic Weighted-Average Common Shares Outstanding | 38,210,187 | 34,892,570 | |||||||||
| Effect of dilutive securities | |||||||||||
| Warrants | 133,007 | 228,232 | |||||||||
| Stock options | 450,255 | 1,108,624 | |||||||||
| Diluted Weighted-Average Common Shares Outstanding | 38,793,449 | 36,229,426 | |||||||||
| Basic Income Per Common Share | |||||||||||
| Net income | 0.17 | 0.52 | |||||||||
| Diluted Income Per Common Share | |||||||||||
| Net Income | 0.17 | 0.51 | |||||||||
For the three months ended March 31, 2009, 780,000 stock options were not included in the computation of diluted income per share as their effects are anti-dilutive.
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.
In June 2008, we entered into an amended agreement that increased the borrowing base under our credit facility to $150,000,000, while leaving the credit facility at $150,000,000. All other terms and conditions remained the same. As of March 31, 2009, we were in compliance with all covenants and did not have any amount 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, 2009 is as follows:
| Balance, January 1, 2009 | $ | 5,066,348 | |||
| Liabilities incurred | 134,232 | ||||
| Accretion expense | 94,750 | ||||
| Balance, March 31, 2009 | $ | 5,295,330 | |||
Compensation expense charged against income for stock based awards during the three months ended March 31, 2009 was $1,329,317, as compared to $1,760,812 for the three months ended March 31, 2008, 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, 2009. Additionally, there were no exercise or forfeitures during the three months ended March 31, 2009. A summary of the status of the stock options as of March 31, 2009 is as follows:
| Options | Weighted-Average Exercise Price | ||||||||||
| Outstanding at December 31, 2008 | 2,252,000 | $ | 22.12 | ||||||||
| Outstanding at March 31, 2009 | 2,252,000 | 22.12 | |||||||||
| Exercisable at March 31, 2009 | 782,000 | $ | 13.10 | ||||||||
As of March 31, 2009, there was approximately $8,132,055 of unrecognized compensation cost related to stock options that will be recognized over a weighted average period of 2.44 years. The aggregate intrinsic value of options expected to vest at March 31, 2009 was $11,754,765. The aggregate intrinsic value of options exercisable at March 31, 2009 was $10,796,320. The intrinsic value is based on a March 31, 2009 closing price of the Company’s common stock of $25.48.
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.
We use commodity–based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. These contracts consist of costless collars. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. At March 31, 2009, we had one costless collar contract covering 275,000 barrels of oil at floor and cap prices of $100.00 to $197.00 per barrel. Their fair value, represented by the estimated amount that would be realized upon termination, based on a comparison of the contract prices and the reference price, on March 31, 2009, was a net unrealized net of tax gain of $7.3 million. These contracts expire monthly through December 2009.
The following table sets forth our derivative volumes as of March 31, 2009:
| Commodity | Remaining Period | Volume | Floor | Ceiling |
|---|---|---|---|---|
| WTI Crude Oil | April 2009 - December 2009 | 275,000 | $ 100 | $ 197 |
Under SFAS No. 133, every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying estimated market price at the determination date. Changes in the fair value of effective cash flow hedges are recorded as a component of “Accumulated other comprehensive income (loss),” (“AOCI”) which is later transferred to earnings when the underlying physical transaction occurs. As of March 31, 2009, an unrealized gain on derivative, net of tax, of $7.3 million was recorded in AOCI. This gain is expected to be reclassified into earnings in 2009. The actual reclassification to earnings will be based on market prices at the contract settlement date.
For those derivative instruments that qualify for hedge accounting, settled transaction gains and losses are determined monthly, and are included in the operating section of our income statement as “Realized loss (gain) on oil derivatives” in the period the hedged production is sold. Our realized gain on oil derivatives includes $5.1 million of gains in the three months ended March 31, 2009 compared to losses of $1.6 million in the three months ended March 31, 2008. Any ineffectiveness associated with these hedges would be reflected in the income statement caption called “Derivative fair value income (loss).” Our hedging contracts are all fully effective.
To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as realized gain or loss on oil derivatives when the underlying transaction occurs. If it is determined that the designated hedge transaction is not probable to occur, any unrealized gains or losses are recognized immediately in the statement of operations as a “Derivative fair value income or loss.” Our hedges are considered to be effective and therefore no amounts have been recorded for ineffectiveness.
The following table presents information about the components of derivative fair value income (loss) in the three months ended March 31, 2009 and 2008:
| For the three months ended March 31, |
|||||
|---|---|---|---|---|---|
| 2009 | 2008 | ||||
| Realized gain (loss) on oil derivative | $ | 5,111,210 | $ | (1,588,440) | |
The combined fair value of derivatives included in our consolidated balance sheets as of March 31, 2009 and December 31, 2008 is summarized below. We conduct derivative activities with one corporation. We believe this corporation is an acceptable credit risk. The credit worthiness of our counterparty is subject to periodic review.
| March 31, 2009 | December 31, 2008 | ||||
| Derivative assets, crude oil collars | $ | 11,597,203 | $ | 16,210,478 | |
We adopted SFAS No. 161 at the beginning of the first quarter of 2009 and the expanded disclosures required by SFAS No. 161. We do not have any derivatives that do not qualify for hedge accounting. The table below provides data about the carrying values of derivatives that qualify for hedge accounting:
| March 31, 2009 | December 31, 2008 | ||||||
| Asset Carrying value |
(Liabilities) Carrying value |
Net Carrying value |
Asset Carrying value |
(Liabilities) Carrying value |
Net Carrying value |
||
| Derivative that qualify as cash flow hedge accounting Collars |
11,597,203 | - | 11,597,203 | 16,210,478 | - | 16,210,478 | |
The table below provides data about the amount of gains and losses related to cash flow derivatives that qualify for hedge accounting included in the balance sheet caption “Accumulated other comprehensive income” (AOCI) and in our statement of operations:
| Amount of Gain/(Loss) recognized in AOCI |
Amount of Gain/(Loss) reclassified from AOCI in Income | |||||||||||
| As of March 31, | As of March 31, | |||||||||||
| 2009 | 2008 | 2009 | 2008 | |||||||||
| Collar | $ | 15,786 | $ | (1,966,823) | $ | 4,629,061 | $ | (1,357,444) | ||||
| Income taxes | (5,841) | 727,725 | (1,712,753) | 502,254 | ||||||||
| Total | $ | 9,945 | $ | (1,239,098) | $ | 2,916,308 | $ | (855,190) | ||||
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 collar. |
| • | 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, 2009 Using: | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Quoted Prices in Active Markets for Identical Liabilities: (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
Total | ||||||||
| Assets/(Liabilities): | |||||||||||
| $100 - $197 Costless collar | $ | - | $ | 11,597,203 | $ | - | $ | 11,597,203 | |||
Subsequent to March 31, 2009, the Company entered into an agreement to extend the maturity period on our existing credit facility. This agreement extended the maturity date to July 15, 2009 to allow the Company to complete negotiations on a new credit facility. At the Company’s election, the extension of the credit facility included a decrease in the borrowing base to $75 million. The facility remained at $150 million and all other terms and conditions remained the same.
Subsequent to March 31, 2009, the Company determined to monetize the balance of its current hedging position. This hedging position is a zero-cost collar on 1,000 barrels of oil per day, with a floor of $100 and a ceiling of $197 and continued through December 2009. The amounts for May 2009 will be paid as usual and the remaining amounts will be paid as a lump sum. Combined these two items will net approximately $9.5 million dollars to the Company.
Subsequent to March 31, 2009, the Company entered into an agreement for zero-cost collars on a portion of oil production, equal to 3,000 net barrels of oil per day, beginning in June 2009 and continuing through December 2009. Under the collar agreements, the Company will receive the difference between an agreed upon average NYMEX WTI index price and a floor price of $50.00, if the index price is below the floor price. The Company will pay the difference between the agreed upon contracted ceiling price of $72.60 and the index price only if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the contracted floor and ceiling prices. We have designated these derivatives for hedge accounting as cash flow hedges.
Results of Operations – For the Three Months Ended March 31, 2009
Oil and natural gas sales. For the three months ended March 31, 2009, oil and natural gas sales revenue decreased $25,119,232 to $20,193,160, compared to $45,312,392 for the same period during 2008. Oil sales decreased $23,677,681 and natural gas sales decreased $1,441,551. The decreases were the result of significantly lower oil and gas prices between periods, partially offset by higher production. For the three months ended March 31, 2009, oil sales volume increased 36,193 barrels to 489,249 barrels, compared to 453,056 barrels for the same period in 2008. The average realized per barrel oil price decreased 60% from $92.10 for the three months ended March 31, 2008 to $36.89 for the three months ended March 31, 2009. For the three months ended March 31, 2009, gas sales volume increased 88,909 thousand cubic feet (MCF) to 472,823 MCF, compared to 383,914 MCF for the same period in 2008. The average realized natural gas price per MCF decreased 51% from $9.34 for the three months ended March 31, 2008 to $4.54 for the three months ended March 31, 2009.
Oil and gas production costs. Our lease operating expenses (LOE) increased from $2,911,925 or $5.63 per barrel of oil equivalent (BOE) for the three months ended March 31, 2008 to $4,206,783 or $7.41 per BOE for the three months ended March 31, 2009. The increases in total LOE and the per BOE amounts were due to our on-going development projects.
Production taxes. Production taxes as a percentage of oil and natural gas sales were 5% during the three months ended March 31, 2008 and remained steady at 5% for the three months ended March 31, 2009. 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 $1,091,548 to $7,231,481 for the three months ended March 31, 2009, compared to the same period in 2008. The increase was primarily a result of an increase in volume and in the average depletion rate from $11.78 per BOE during the three months ended March 31, 2008 to $12.60 per BOE during the three months ended March 31, 2009. The increased depletion rate was the result of increased capitalized costs and development costs.
General and administrative expenses. General and administrative expenses increased by $51,786 to $2,674,769 for the three months ended March 31, 2009, compared to the same period in 2008. The increase was primarily the result of increases in compensation expense, partially offset by a decrease in stock-based compensation expense from $1,760,812 for the three months ended March 31, 2008 to $1,329,317 for the three months ended March 31, 2009.
Interest income. Interest income was $266,312 for the three months ended March 31, 2009, compared to $40,961 for the three months ended March 31, 2008. The increase was due to higher cash balances between periods.
Interest expense. Interest expense was zero for the three months ended March 31, 2009, compared to $615,080 for the three months ended March 31, 2008. The decrease was due to no amounts being outstanding during the three months ended March 31, 2009 while there were amounts outstanding during the three months ended March 31, 2008.
Income tax expense. Our effective tax rate was 37% during the three months ended March 31, 2008 and remained steady at 37% for the three months ended March 31, 2009.
Net income. Net income decreased from $18,318,395 for the three months ended March 31, 2008 to $6,465,449 for the same period in 2009. The primary reason for this decrease is the lower commodity prices between periods.
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 | 427,197 | BBLS | $ | 15,776,390 |
| Oklahoma Leases | 7,949 | BBLS | $ | 326,883 |
| New Mexico Leases | 54,103 | BBLS | $ | 1,944,652 |
| Net Production Volume | Net Revenue | |||
| Texas Leases | 350,155 | MCF | $ | 1,621,879 |
| Oklahoma Leases | 3,930 | MCF | $ | 13,037 |
| New Mexico Leases | 83,827 | MCF | $ | 395,937 |
| Kansas Leases | 34,911 | MCF | $ | 114,382 |
Significant Subsequent Events occurring after March 31, 2009:
Subsequent to March 31, 2009, the Company entered into an agreement to extend the maturity period on our existing credit facility. This agreement extended the maturity date to July 15, 2009 to allow the Company to complete negotiations on a new credit facility. At the Company’s election, the extension of the credit facility included a decrease in the borrowing base to $75 million. The facility remained at $150 million and all other terms and conditions remained the same.
Subsequent to March 31, 2009, the Company determined to monetize the balance of its current hedging position. This hedging position is a zero-cost collar on 1,000 barrels of oil per day, with a floor of $100 and a ceiling of $197 and continued through December 2009. The amounts for May 2009 will be paid as usual and the remaining amounts will be paid as a lump sum. Combined these two items will net approximately $9.5 million dollars to the Company.
Subsequent to March 31, 2009, the Company entered into an agreement for zero-cost collars on a portion of oil production, equal to 3,000 net barrels of oil per day, beginning in June 2009 and continuing through December 2009. Under the collar agreements, the Company will receive the difference between an agreed upon average NYMEX WTI index price and a floor price of $50.00, if the index price is below the floor price. The Company will pay the difference between the agreed upon contracted ceiling price of $72.60 and the index price only if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the contracted floor and ceiling prices. We have designated these derivatives for hedge accounting as cash flow hedges.
Capital Resources and Liquidity
As shown in the financial statements for the three months ended March 31, 2009, the Company had cash on hand of $52,403,274, compared to $58,489,574 as of December 31, 2008. The Company had net cash provided by operating activities for the three months ended March 31, 2009 of $11,231,316, compared to $35,480,006 for the same period 2008. Other significant sources of cash inflow in 2008 were $5,500,000 drawn down on the Company’s credit facility and proceeds from option and warrant exercises of $1,566,844. The most significant cash outflows during the three months ended March 31, 2009 and 2008 were capital expenditures of $17,317,616 in 2009 and $41,068,121 in 2008.
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.
In June 2008, we entered into an amended agreement that increased the borrowing base under our credit facility to $150,000,000, while leaving the credit facility at $150,000,000. All other terms and conditions remained the same. As of March 31, 2009, we were in compliance with all covenants and did not have any amount 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 2008 the Company entered into a derivative contract in order to manage the commodity price risk for a portion of production through 2009. 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, 2009.
| Commodity | Remaining Period | Volume | Floor | Ceiling |
|---|---|---|---|---|
| WTI Crude Oil | April 2009 - December 2009 | 275,000 | $ 100.00 | $ 197.00 |
The change in fair value of the oil hedging contract in place at March 31, 2009, resulted in a decrease in the asset of $4,613,275, to $11,597,203. The after tax impact of the change in the fair value of the hedge of $2,906,363 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 gain on derivatives in the operating section of the Company’s statement of operations. Our statement of operations for the three months ended March 31, 2009 includes a gain on derivative instrument of $5,111,210 as compared to a loss of $1,558,440 for the three months ended March 31, 2008.
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 6, 2009 | By: /s/ Phillip W. Terry |
| Phillip W. Terry | |
| President, Chief Executive Officer |
| Dated: May 6, 2009 | By: /s/ William R. Broaddrick |
| William R. Broaddrick | |
| Vice President, Chief Financial Officer |