Edgar Filing: ARENA RESOURCES INC

arena_10k123109.htm

United States Securities and Exchange Commission

Washington, D.C. 20549

Form 10-K

(Mark One)
þ	Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 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 Number)

6555 South Lewis Avenue Tulsa, Oklahoma		74136
(Address of principal executive offices)		(Zip Code)

(918) 747-6060

(Registrant’s telephone number, including area code)

____________________________

Securities registered under Section 12(b) of the Exchange Act:

Title of Each Class		Name of Each Exchange On Which Registered
Common - $0.001 Par Value		New York Stock Exchange

Securities registered under Section 12(g) of the Exchange Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes þ No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ¨ No þ

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ¨ Yes ¨ No þ Not Applicable

Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer.

Large accelerated filer þ Accelerated filer ¨ Non-accelerated filer ¨

Indicate by check mark whether the registrant is shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No þ

As of June 30, 2009, the aggregate market value of the common voting stock held by non-affiliates of the issuer, based upon the closing stock price of $31.85 per share, was approximately $1,195,116,500.

As of March 1, 2010, the issuer had outstanding 38,793,963 shares of common stock ($0.001 par value).

TABLE OF CONTENTS

PART I
		Page

Item 1	Business	4

Item 1A	Risk Factors	8

Item 1B	Unresolved Staff Comments	14

Item 2	Properties	14

Item 3	Legal Proceedings	25

Item 4	Submission of Matters to a Vote of Security Holders	25

PART II

Item 5	Market for Registrant's Common Equity, Related Stockholder Matters	27
	and Issuer Purchases of Equity Securities

Item 6	Selected Financial Data	28

Item 7	Management's Discussion and Analysis of Financial Condition	28
	and Results of Operations

Item 7A	Quantitative and Qualitative Disclosures About Market Risk	36

Item 8	Financial Statements and Supplementary Data	36

Item 9	Changes in and Disagreement's With Accountants on Accounting	36
	and Financial Disclosure

Item 9A	Controls and Procedures	37

Item 9B	Other Information	39

PART III

Item 10	Directors, Executive Officers and Corporate Governance	40

Item 11	Executive Compensation	43

Item 12	Security Ownership of Certain Beneficial Owners and Management	49
	and Related Stockholder Matters

Item 13	Certain Relationships and Related Transactions, and Director Independence	51

Item 14	Principal Accounting Fees and Services	51

PART IV

Item 15	Exhibits	52

Forward Looking Statements

All statements, other than statements of historical fact included in this Annual Report on Form 10-K (herein, “Annual Report”) regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. All forward-looking statements speak only as of the date of this Annual Report. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Unless the context otherwise requires, references in this Annual Report to “Arena,” “we,” “us,” “our” or “ours” refer to Arena Resources, Inc.

PART I

Item 1: Business

General

Arena Resources, Inc. was incorporated in Nevada on August 31, 2000. Our principal executive offices are located at 6555 South Lewis Avenue, Tulsa, Oklahoma 74136, and our telephone number is (918) 747-6060. Our Internet website can be found at www.arenaresourcesinc.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act of 1934 will be available through our Internet website as soon as reasonably practical after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

We are engaged in oil and natural gas acquisition, exploration, development and production, with activities currently in Oklahoma, Texas, New Mexico and Kansas. Our focus will be on developing our existing properties, while continuing to pursue acquisitions of oil and gas properties with upside potential.

Business Development

Between our inception in August 2000 through 2004, we built our asset base and achieved growth primarily through property acquisitions. Beginning in 2005, while we continued to grow through acquisition, we shifted our focus to growth through development of our existing properties. From our inception through December 31, 2009, we have increased our proved reserves to approximately 69.5 million Boe (barrel of oil equivalent). As of December 31, 2009, our estimated proved reserves had a pre-tax PV10 (present value of future net revenues before income taxes discounted at 10%) of approximately $1.12 billion and a Standardized Measure of Discounted Future Net Cash Flows of approximately $754.2 million. The difference between these two amounts is the effect of income taxes. The Company presents the pre-tax PV-10 value, which is a non-GAAP financial measure, because it is a widely used industry standard which we believe is useful to those who may review this Annual Report when comparing our asset base and performance to other comparable oil and gas exploration and production companies. We spent approximately $485.6 million on acquisitions and capital projects during 2007, 2008 and 2009.

We have a portfolio of oil and natural gas reserves, with approximately 86% of our proved reserves consisting of oil and approximately 14% consisting of natural gas. Of those reserves approximately 33% of our proved reserves are classified as proved developed producing, or “PDP,” approximately 5% of our proved reserves are classified as proved developed behind pipe, or “PDBP,” and approximately 62% are classified as proved undeveloped, or “PUD.”

Competitive Business Conditions

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Some of our competitors possess and employ financial resources substantially greater than ours and some of our competitors employ more technical personnel. These factors can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than what our financial or technical resources permit. Our ability to acquire additional properties and to find and develop reserves in the future will depend on our ability to identify, evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry.

The actual price range of crude oil is largely established by major crude oil purchasers and commodities trading. Pricing for natural gas is based on regional supply and demand conditions. To this extent we believe we receive oil and gas prices comparable to other producers. There is little risk in our ability to sell all our current production at current prices with a reasonable profit margin. The risk of domestic overproduction at current prices is not deemed significant. We view our primary pricing risk to be related to a potential decline in prices to a level which could render our current production uneconomical.

We are presently committed to use the services of the existing gathering systems of the companies that purchase our natural gas production. This commitment is tied to existing natural gas purchase contracts associated with our production This commitment potentially gives such gathering companies 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 gathering company would be required to lay new pipeline and/or obtain new rights of way to any lease from which we are selling production). We are not subject to third party gathering systems for our oil production. Some of our oil production is sold through a third party pipeline which has no regional competition. All other oil production is transported by the oil purchaser by trucks with competitive trucking costs in the area.

Major Customers

We principally sell our oil and natural gas production to end users, marketers and other purchasers that have access to nearby pipeline facilities. In areas where there is no practical access to pipelines, oil is trucked to storage facilities. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted. For fiscal year 2009, sales to three customers, Navajo Refining Company, ConocoPhillips and DCP Midstream, LP, represented 75%, 13% and 8% of oil and gas revenues, respectively. At December 31, 2009, these customers represented 74%, 14% and 7% of our accounts receivable. However, we believe that the loss of these customers would not materially impact our business, because we could readily find other purchasers for our oil and gas as produced.

Delivery Commitments

As of December 31, 2009, we are not committed to providing a fixed quantity of oil or gas under any existing contracts.

Governmental Regulations

Regulation of Transportation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission, or the FERC, regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state.

Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors. Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Regulation of Transportation and Sale of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Therefore, we cannot provide any assurance that the less stringent regulatory approach established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.

Regulation of Production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental Compliance and Risks

Our oil and natural gas exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. 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 we believe this generally to be the case for our production activities in Oklahoma, Texas, New Mexico and Kansas, there are various regulations issued by the Environmental Protection Agency (“EPA”) and other governmental agencies that would govern significant spills, blow-outs, or uncontrolled emissions.

In Oklahoma, Texas, New Mexico and Kansas specific oil and gas regulations apply to the drilling, completion and operations of wells, and the disposal of waste oil and salt water. There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.

At the federal level, among the more significant laws and regulations that may affect our business and the oil and gas industry are: The Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as “CERCLA” or “Superfund; the Oil Pollution Act of 1990; the Resource Conservation and Recovery Act, also known as “RCRA,”; the Clean Air Act; Federal Water Pollution Control Act of 1972, or the Clean Water Act; and the Safe Drinking Water Act of 1974.

Compliance with these regulations may constitute a significant cost and effort for us. No specific accounting for environmental compliance has been maintained or projected by us at this time. We are not presently aware of any environmental demands, claims, or adverse actions, litigation or administrative proceedings in which either we or our acquired properties are involved in or subject to, or arising out of any predecessor operations.

In the event of a breach of environmental regulations, these environmental regulatory agencies have a broad range of alternative or cumulative remedies which include: ordering a clean-up 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 us or our principal officers.

Current Employees

As of December 31, 2009, we had 120 full-time employees, including 48 employed by Arena Drilling Company, a wholly owned subsidiary. Our employees are not represented by any labor union. We consider our relations with our employees to be satisfactory and have never experienced a work stoppage or strike.

We retain certain engineers, geologists, landmen, pumpers and other personnel on a contract or fee basis as necessary for our operations.

Item 1A. Risk Factors

The following risks and uncertainties may affect our performance, results of operations and the trading price of our common stock.

Risks Relating to the Oil and Natural Gas Industry and Our Business

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

• changes in global supply and demand for oil and natural gas;

• the actions of the Organization of Petroleum Exporting Countries, or OPEC;

• the price and quantity of imports of foreign oil and natural gas;

• political conditions, including embargoes, in or affecting other oil-producing activity;

• the level of global oil and natural gas exploration and production activity;

• the level of global oil and natural gas inventories;

• weather conditions;

• technological advances affecting energy consumption; and

• the price and availability of alternative fuels.

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. Lower prices will also negatively impact the value of our proved reserves. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

A substantial percentage of our proven properties are undeveloped; therefore the risk associated with our success is greater than would be the case if the majority of our properties were categorized as proved developed producing.

Because a substantial percentage of our proven properties are proved undeveloped (approximately 62%) or proved developed behind pipe (approximately 5%), we will require significant additional capital to develop such properties before they may become productive. Further, because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be developed to the extent that they result in positive cash flow. Even if we are successful in our development efforts, it could take several years for a significant portion of our undeveloped properties to be converted to positive cash flow.

While our current business plan is to fund the development costs with cash flow from our other producing properties, if such cash flow is not sufficient we may be forced to seek alternative sources for cash, through the issuance of additional equity or debt securities, increased borrowings or other means.

Approximately 23% of our proven reserves depend upon secondary recovery techniques to establish production.

Approximately twenty-three percent (23%) of our reserves for the year ended December 31, 2009 are associated with secondary recovery projects that are either in the initial stage of implementation or are scheduled for implementation. We anticipate that secondary recovery will be attempted by the use of waterflood of these reserves, and the exact project initiation dates and, by the very nature of waterflood operations, the exact completion dates of such projects are uncertain. In addition, the reserves associated with these secondary recovery projects, as with any reserves, are estimates only, as the success of any development project, including these waterflood projects, cannot be ascertained in advance. If we are not successful in developing a significant portion of our reserves associated with secondary recovery methods, it could have a negative impact on our earnings and our stock price.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control; including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Please read “—Reserve estimates depend on many assumptions that may turn out to be inaccurate” (below) for a discussion of the uncertainty involved in these processes. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:

• delays imposed by or resulting from compliance with regulatory requirements;

• pressure or irregularities in geological formations;

• shortages of or delays in obtaining equipment and qualified personnel;

• equipment failures or accidents;

• adverse weather conditions;

• reductions in oil and natural gas prices;

• title problems; and

• limitations in the market for oil and natural gas.

If our assessments of recently purchased properties are materially inaccurate, it could have significant impact on future operations and earnings.

We have aggressively expanded our base of producing properties. The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following:

• the amount of recoverable reserves;

• future oil and natural gas prices;

• estimates of operating costs;

• estimates of future development costs;

• estimates of the costs and timing of plugging and abandonment; and

• potential environmental and other liabilities.

Our assessment will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. As noted previously, we plan to undertake further development of our properties through the use of cash flow from existing production. Therefore, a material deviation in our assessments of these factors could result in less cash flow being available for such purposes than we presently anticipate, which could either delay future development operations (and delay the anticipated conversion of reserves into cash), or cause us to seek alternative sources to finance development activities.

Decreases in oil and natural gas prices may require us to take write-downs of the carrying values of our oil and natural gas properties, potentially requiring earlier than anticipated debt repayment and negatively impacting the trading value of our securities.

Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. Because our properties serve as collateral for advances under our existing credit facilities, a write-down in the carrying values of our properties could require us to repay debt earlier than we would otherwise be required. A write-down could also constitute a non-cash charge to earnings. It is likely the cumulative effect of a write-down could also negatively impact the trading price of our securities.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reported reserves.

In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reported reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our reported proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. If future values decline or costs increase it could negatively impact our ability to finance operations, and individual properties could cease being commercially viable, affecting our decision to continue operations on producing properties or to attempt to develop properties. All of these factors would have a negative impact on earnings and net income, and most likely the trading price of our securities. These factors could also result in the acceleration of debt repayment and a reduction in our borrowing base under our credit facilities.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Our prospects are in various stages of evaluation, ranging from prospects that are currently being drilled, to prospects that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. This risk may be enhanced in our situation, due to the fact that a significant percentage (62%) of our proved reserves is currently proved undeveloped reserves. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

• environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

• abnormally pressured formations;

• mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

• fires and explosions;

• personal injuries and death; and

• natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our company. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, then it could adversely affect us.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

Exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:

• discharge permits for drilling operations;

• drilling bonds;

• reports concerning operations;

• the spacing of wells;

• unitization and pooling of properties; and

• taxation.

Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.

Our operations may incur substantial liabilities to comply with the environmental laws and regulations.

Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition as well as the industry in general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed.

If our indebtedness increases, it could reduce our financial flexibility.

We have a $150 million credit facility in place with a current borrowing base of $75 million and the structure in place to increase that borrowing base an additional $75 million. As of December 31, 2009, no amount was outstanding on our credit facility. If in the future we utilize this facility, the level of our indebtedness could affect our operations in several ways, including the following:

• a significant portion of our cash flow could be used to service the indebtedness,

• a high level of debt would increase our vulnerability to general adverse economic and industry conditions,

• the covenants contained in our credit facility limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments,

• a high level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

In addition, our bank borrowing base is subject to semi-annual redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. If we are unable to develop, exploit, find or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of sustaining commercial production.

If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business.

Currently, the majority of our production is sold to marketers and other purchasers that have access to nearby pipeline facilities. However, as we begin to further develop our properties, we may find production in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas have several adverse affects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

Hedging transactions may limit our potential gains.

In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. Our hedges, consisting of a series of contracts, are limited in duration, usually for periods of one to three years. While intended to reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains if crude oil and natural gas prices rise over the price established by the arrangements.

Risks Relating to Our Common Stock

We have no plans to pay dividends on our common stock. You may not receive funds without selling your shares.

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. In addition, our credit facility prohibits us from paying dividends.

Provisions under Nevada law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock.

While we do not believe that we currently have any provisions in our organizational documents that could prevent or delay a change in control of our company (such as provisions calling for a staggered board of directors, or the issuance of stock with super-majority voting rights), the existence of some provisions under Nevada law could delay or prevent a change in control of our company, which could adversely affect the price of our common stock. Nevada law imposes some restrictions on mergers and other business combinations between us and any holder of 10% or more of our outstanding common stock.

Item 1B: Unresolved Staff Comments

None.

Item 2: Properties

General Background

From our inception in August 2000 through 2004, we built our asset base and achieved growth primarily through property acquisitions. Beginning in 2005, while we have continued to grow through acquisition, we have shifted our focus to growth through development of our existing properties.

As of December 31, 2009, our estimated proved reserves had a pre-tax PV10 value of approximately $1.12 billion and a Standardized Measure of Discounted Future Cash Flows of approximately $754.2 million, approximately 80% of which relate to our properties in Texas, approximately 15% of which relate to our properties located in New Mexico, approximately 4% relate to our properties in Oklahoma and less than 1% relate to our properties in Kansas. We spent approximately $485.6 million on acquisitions and capital projects during 2007, 2008 and 2009. We expect to further develop these properties through additional drilling. We will closely manage our capital expenditures to our cash flow. As commodity prices change we will consider the resulting impact on our cash flow and adjust our capital expenditures up or down accordingly. We have maintained a strong current cash position with no long-term debt; we will continue to seek acquisition opportunities that complement our core assets.

The following table summarizes our total net proved reserves, pre-tax PV10 value and Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2009.

Geographic Area	Oil (Bbl)		Natural Gas (Mcf)		Total (Boe)		Pre-Tax PV10 Value		Standardized Measure of Discounted Future Net Cash Flows
New Mexico		9,012,390		7,979,726		10,342,345	$	185,626,509	$	123,864,486
Texas		47,973,061		47,946,793		55,964,193		877,877,087		592,237,629
Oklahoma		2,730,061		228,959		2,768,221		57,048,503		37,116,698
Kansas		-		1,059,210		176,535		805,401		1,014,944

Total		59,715,512		57,214,688		69,251,294	$	1,121,357,500	$	754,233,757

Proved Reserves

Our 69,251,294 Boe of proved reserves, which consist of approximately 86% oil and 14% natural gas, are summarized below as of December 31, 2009, on a net pre-tax PV10 value and Standardized Measure of Discounted Future Net Cash Flows basis. Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC).

As of December 31, 2009, our Texas proved reserves had a net pre-tax PV10 value of $877.9 million and Standardized Measure of Discounted Future Net Cash Flows of $592.2 million, our proved reserves in New Mexico had a net pre-tax PV10 value of $185.6 million and Standardized Measure of Discounted Future Net Cash Flows of $123.9 million, our proved reserves in Oklahoma had a net pre-tax PV10 value of $57.0 million and a Standardized Measure of Discounted Future Net Cash Flows of $37.1 million and our proved reserves in Kansas had a net pre-tax PV10 value of $0.8 million and a Standardized Measure of Discounted Future Net Cash Flows of $1.0 million.

As of December 31, 2009, approximately 33% of the proved reserves have been classified as proved developed producing, or “PDP”. Proved developed behind pipe, or “PDBP” reserves constitute approximately 5% and proved undeveloped, or “PUD”, reserves constitute approximately 62%, of the proved reserves as of December 31, 2009.

Total proved reserves had a net pre-tax PV10 value as of December 31, 2009 of approximately $1.12 billion and a Standardized Measure of Discounted Future Net Cash Flows of approximately $754.2 million, 35.1% or $394.0 million and $265.7 million, respectively, of which is associated with the PDP reserves. An additional $69.5 million and $46.6 million, respectively, is associated with the PDBP reserves, or 6.2% of total proved reserves’ pre-tax PV10 value. The remaining $657.9 million and $441.9 million, respectively, is associated with PUD reserves.

Proved Reserves Disclosures

Recent SEC Rule-Making Activity. In December 2008, the SEC announced that it had approved revisions to modernize the oil and gas reserve 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.

·	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. We have chosen not to make disclosure under these categories.

·	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 adopted the rules effective December 31, 2009.

The new rule does not allow for prior-year reserve information to be restated, so all information related to periods prior to 2009 is presented consistent with prior SEC rules for the estimation of proved reserves.

Internal Controls Over Reserves Estimates. Our reserves estimates are prepared internally by our Reservoir/Acquisitions Manager and our Reservoir Studies Manager in compliance with SEC definitions and guidance and in accordance with generally accepted petroleum engineering principles. Our Reservoir/Acquisitions Manager holds a Bachelor of Science in Petroleum Engineering and has over thirty (30) years of industry experience in property evaluations and reserves estimates preparation. Our Reservoir Studies Manager holds a Bachelor of Science and Master of Science in Petroleum Engineering and has over 37 years of industry experience in reservoir engineering, property evaluations, and reserves estimates preparation. Our reserves estimates are prepared by examination and evaluation of production data, production decline curves, reservoir pressure data, logs, geological data, and offset analogies. Our reserves estimates are reviewed and approved by our Operations Vice President and our President/Chief Executive Officer. Our Chief Financial Officer reviews the reserves estimates to assure compliance with SEC reporting requirements.

We engage third-party petroleum consulting firms to audit all of our reserves. See the Third-Party Reserves Audit report in exhibits.

Proved Undeveloped Reserves – Our reserve estimates as of December 31, 2009 include 43.4 million BOE as proved undeveloped reserves. As of December 31, 2008, our reserve estimates included 40.6 BOE as proved undeveloped reserves. Following is a description of the changes in our PUD reserves from December 31, 2008 to December 31, 2009.

Conversion of approximately 5.2 million BOE of reserve from PUD to PDP or PDBP through capital expenditures of approximately $58.4 million.

Downward revision of approximately 8.6 million BOE as a result of commodity price changes and revisions of estimates due to performance.

Recording of approximately 16.6 million BOE in new PUD reserves as a result of acquisitions and our continuing development of additional acreage.

Our proved reserves as of December 31, 2009 are summarized in the table below.

	Oil (Bbl)		Gas (Mcf)		Total (Boe)		% of Total Proved			Pre-tax PV10 (In thousands)		Standardized Measure of Discounted Future Net Cash Flows (In thousands)		Future Capital Expenditures (In thousands)

New Mexico:
PDP		3,116,024		4,420,485		3,852,772		6	%	$	53,780	$	35,886	$	-
PDBP		1,456,110		1,274,437		1,668,516		2	%	$	34,653		23,123		2,735
PUD		4,440,256		2,284,804		4,821,057		7	%	$	97,194		64,855		40,215

Total Proved:		9,012,390		7,979,726		10,342,345		15	%	$	185,627	$	123,864	$	42,950


Texas:
PDP		14,920,662		18,859,572		18,063,924		26	%	$	332,309	$	224,184	$	-
PDBP		1,243,307		2,589,005		1,674,808		2	%	$	34,795		23,474		10,236
PUD		31,809,092		26,498,216		36,225,461		52	%	$	510,773		344,580		483,567

Total Proved:		47,973,061		47,946,793		55,964,193		80	%	$	877,877	$	592,238	$	493,803


Oklahoma:
PDP		408,803		99,760		425,430		1	%	$	7,084	$	4,609	$	-
PUD		2,321,258		129,199		2,342,791		3	%	$	49,965		32,508		6,270

Total Proved:		2,730,061		228,959		2,768,221		4	%	$	57,049	$	37,117	$	6,270


Kansas:
PDP		-		1,059,210		176,535		1	%	$	805	$	1,015	$	-

Total Proved:		-		1,059,210		176,535		1	%	$	805	$	1,015	$	-


Total:
PDP		18,445,489		24,439,027		22,518,661		33	%	$	393,978	$	265,694	$	-
PDBP		2,699,417		3,863,442		3,343,324		5	%		69,448		46,597		12,971
PUD		38,570,606		28,912,219		43,389,309		62	%		657,932		441,943		530,052

Total Proved:		59,715,512		57,214,688		69,251,294		100	%	$	1,121,358	$	754,234	$	543,023

Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves

The following table indicates projected reserves that we currently estimate will be converted from proved undeveloped or proved developed non-producing to proved developed, as well as the estimated costs per year involved in such development.

Year	Estimated Oil Reserves Developed (Bbls)		Estimated Gas Reserves Developed (Mcf)		Total Boe		Estimated Development Costs

2010		15,262,194		12,262,170		17,305,889	$	153,627,173
2011		11,963,553		8,237,414		13,336,455		179,091,886
2012		9,818,416		9,494,082		11,400,763		182,626,316
2013		2,166,220		1,343,823		2,390,191		19,897,500
Remaining		2,059,640		1,438,172		2,299,335		7,780,000

		41,270,023		32,775,661		46,732,633	$	543,022,875

Production

Our estimated average daily production for the month of December, 2009, is summarized below. These tables indicate the percentage of our estimated December 2009 average daily production of 7,254 Boe/d attributable to each state and to oil versus natural gas production.

State	Average Daily Production			Oil			Natural Gas

Texas		88.23	%		75.48	%		12.75	%

New Mexico		8.73	%		7.09	%		1.65	%

Oklahoma		2.26	%		2.16	%		0.10	%

Kansas		0.77	%		0.00	%		0.77	%

Total		100.00	%		84.73	%		15.27	%

Summary of Oil and Natural Gas Properties and Projects

Significant New Mexico Operations

East Hobbs San Andres Unit – Lea County, New Mexico. In May, 2004 we acquired an 82.24% working interest and a 67.60% net revenue interest in this lease. The property has been in continuous production since that time. “Net revenue interest” is the owner’s percentage share of the monthly income realized from the sale of a well’s produced oil and gas. The net revenue interest is a lesser number as compared to the working interest, due to the mineral owner royalty and other overriding royalties on the well. The lease contains approximately 920 acres, all held by production, on which there are 31 producing wells. We believe the property has additional potential through waterflooding. A waterflood operation is a method of secondary recovery in which water is injected into the reservoir formation to displace residual oil. The water from injection wells physically sweeps the displaced oil to adjacent production wells. These estimates are included in our estimates of PUD potential.

Humphrey Queen Unit – Lea County, New Mexico. We acquired a 100% working interest and a 75.08% net revenue interest in this mature waterflood in December, 2007. The property contains 16 producing wells and approximately 760 acres, all held by production. We believe the property can support activities to drill 12 additional PUD wells, which are included in our reserve estimates.

Langlie Mattix Queen Unit – Lea County, New Mexico. We acquired a 100% working interest and a 75.09% net revenue interest in this mature waterflood property in December, 2007. The property has 16 producing wells on approximately 1,040 acres, all held by production. We believe the property can support activity to drill 14 additional PUD wells, which are included in our reserve estimates.

South Leonard Queen Unit – Lea County, New Mexico. We acquired a 100% working interest and a 75.09% net revenue interest in this mature waterflood in December, 2007. The property contains seven producing wells on approximately 680 acres with all of the acreage being held by production. We believe the property can support activity to drill four additional PUD wells, which are included in our reserve estimates.

North Benson Queen Unit – Eddy County, New Mexico. We acquired a 100% working interest and a 69.44% net revenue interest in this mature waterflood property in October, 2003. The property has 27 producing wells and contains approximately 1,800 acres, all held by production. We have reactivated the waterflood by constructing a new water supply system, building new injection facilities, and returning previously idle water injection wells to service. We think the property can support workovers in existing wells to open additional zones and drilling 28 additional wells which are included as PUD in our reserve estimate.

Red Lake Unit – Eddy County, New Mexico. In October, 2007 we acquired a 100% working interest and an 80.56% net revenue interest in this property. The lease has 16 producing wells on approximately 1,090 acres, all held by production. We believe the property can support activity to drill three additional PUD wells, which are included in our reserve estimates.

Phillips Lea, Hale State, State 36 and Corbin 35 leases – Lea County, New Mexico. In June, 2008 we acquired a 100% working interest with net revenue interests ranging from 80.31% to 82.81% in these leases. The leases have 16 producing wells on approximately 800 acres, all held by production. We think the property can support workovers in existing wells to open new zones in existing wells and drilling 10 additional wells which are included as PUD in our reserve estimate.

Significant Texas Operations

Fuhrman Mascho leases – Andrews County, Texas. In December 2004 we acquired a 100% working interest and a 75% net revenue interest in these leases. Throughout 2005 through 2009 we acquired working and net revenue interests in additional producing leases and acquired additional undeveloped acreage in and around our Fuhrman Mascho leases. The working interests range from 20-100% and the net revenue interests range from 16-80%. In total, we now own 46,888 acres, with 35,246 acres developed and held by production and the remaining 11,642 acres being undeveloped. We believe the Fuhrman Mascho leases contain considerable remaining potential drilling. Our reserve estimate includes 941 PUD wells. Our reserve estimates include potential development expenditures.

Y6 lease – Fisher County, Texas. We acquired a 100% working interest and an 80% net revenue interest in this partially developed waterflood property in June, 2001. There are 15 producing wells on approximately 1,697 acres, which is held by production. We believe the property can support activity to drill four additional PUD wells, which are included in our reserve estimates.

Significant Oklahoma Operations

Ona Morrow Sand Unit – Cimarron and Texas Counties, Oklahoma. We acquired a 100% working interest and an 81.32% net revenue interest in this waterflood property in June, 2001. There are 13 producing wells on approximately 2,120 acres, which is held by production. We believe the property can support three additional PUD wells, which are included in our estimate of PUD.

Midwell, Appleby, Smaltz, and Hanes Leases – Cimarron County, Oklahoma. We acquired a 100% working interest and an 80% net revenue interest in these leases in September, 2002. The leases contain 11 wells on approximately 2,280 acres, which is held by production. We believe the leases contain PUD potential from waterflood operations and six PUD wells, which are included in our estimate of PUD. We began implementing the waterflood operations and will continue those efforts.

Acreage

The following table summarizes gross and net developed and undeveloped acreage at December 31, 2009 by region (net acreage is our percentage ownership of gross acreage). Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.

	Developed Acreage		Undeveloped Acreage		Total Acreage

	Gross	Net	Gross	Net	Gross	Net
New Mexico	9,850	9,038	-	-	9,850	9,038

Texas	34,569	33,923	16,116	14,411	50,685	48,335

Oklahoma	5,529	5,046	-	-	5,529	5,046

Kansas	5,200	5,200	0	0	5,200	5,200

Total	55,148	53,206	16,116	14,411	71,264	67,618

Production History

The following table presents the historical information about our produced natural gas and oil volumes.

			Year Ended December 31,
			2007	2008	2009

Oil production (Bbls)			1,316,025	2,018,335	2,004,498
Natural gas production (Mcf)			1,503,611	1,911,713	2,172,790
Total production (Boe)			1,566,627	2,336,954	2,366,630
Daily production (Boe/d)			4,292	6,385	6,484
Average sales price:
	Oil (per Bbl)		$ 66.89	$ 94.16	$ 57.51
	Natural gas (per Mcf)		8.02	9.84	5.04
		Total (per Boe)	63.89	89.37	53.34
Average production cost (per Boe)			$ 7.34	$ 7.63	$ 6.57
Average production taxes (per Boe)			3.61	4.50	2.73

The average oil sales price amounts above are calculated by dividing revenue from oil sales by the volume of oil sold, in Bbl. The average gas sales price amounts above are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The total average sales price amounts are calculated by dividing total revenues by total volume sold, in Boe. The average production costs above are calculated by dividing production costs by total production in Boe.

Productive Wells

The following table presents our ownership at December 31, 2009, in productive oil and natural gas wells by region (a net well is our percentage ownership of a gross well).

	Oil Wells		Gas wells		Total Wells
	Gross	Net	Gross	Net	Gross	Net
New Mexico	194	173	-	-	194	173
Texas	893	876	-	-	893	876
Oklahoma	36	32	-	-	36	32
Kansas	-	-	10	10	10	10

Total	1,123	1,080	10	10	1,133	1,090

Drilling Activity

The following table represents our drilling activity for the years ended December 31, 2007, 2008 and 2009:

		2007		2008		2009
		Gross	Net	Gross	Net	Gross	Net
Productive development wells
	Texas	133	130	223	219	176	173
	Oklahoma	1	1	-	-	-	-
	New Mexico	-	-	1	1	5	4

	Total productive development wells	134	131	224	220	181	177
Dry development wells		-	-	-	-	-	-

Total development wells		134	131	224	220	181	177

Productive exploratory wells		-	-	-	-	-	-
Dry exploratory wells
	Texas	-	-	-	-	1	1

	Total dry exploratory wells	-	-	-	-	1	1

Total exploratory wells		-	-	-	-	-	-

Total productive wells		134	131	224	220	181	177
Total dry wells		-	-	-	-	1	1

Total wells drilled		134	131	224	220	182	178

As of December 31, 2009, we were in the process of drilling five wells with an additional fourteen wells in various stages of completion, all in Texas. While we have small working interest partners in three of these wells, we own the majority of the working interest; therefore this information is correct for both gross and net wells.

Cost Information

We conduct our oil and natural gas activities entirely in the United States. As noted previously in the table appearing under “Production History”, our average production costs, per Boe, were $7.34 in 2007, $7.63 in 2008 and $6.57 in 2009 and our average production taxes, per BOE, were $3.61 in 2007, $4.50 in 2008 and $2.73 in 2009. These amounts are calculated by dividing our total production costs or total production taxes by our total volume sold, in Boe.

Costs incurred for property acquisition, exploration and development activities during the years ended December 31, 2007, 2008 and 2009 are shown below.

	For the Years Ended December 31,
	2007 (1)		2008		2009
Acquisition of proved properties	$	53,554,064	$	16,782,225	$	3,942,103
Acquisition of unproved properties		542,650		-		-
Exploration costs		-		-		-
Development costs		113,084,344		190,584,617		107,064,257
Total Costs Incurred	$	167,181,058	$	207,366,842	$	111,006,360

(1) The amount shown for 2007 for acquisition of proved properties is net of proceeds received from the sale of our interest in the West San Andres property.

Reserve Quantity Information

Our estimates of proved reserves and related valuations were based on internal reports and audited by Williamson Petroleum Consultants, Inc. independent petroleum engineers. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in quantities of proved (developed and undeveloped) oil and natural gas reserves is shown below.

				Natural Gas
		Oil (Bbls)		(Mcf)
Balance, December 31, 2006		36,064,273		42,424,199
	Purchase of minerals in place	7,021,972		4,330,246
	Extensions and discoveries	6,016,660		6,852,346
	Production	(1,316,023	)	(1,503,611	)
	Revisions of estimates	(373,560	)	(4,028,218	)

Balance, December 31, 2007		47,413,322		48,074,962
	Purchase of minerals in place	3,638,095		2,364,908
	Extensions and discoveries	9,547,981		11,391,853
	Production	(2,018,335	)	(1,911,713	)
	Revisions of estimates	(2,735,806	)	(1,115,348	)

Balance, December 31, 2008		55,845,257		58,804,662
	Purchase of minerals in place	1,589,141		2,791,611
	Extensions and discoveries	14,360,492		13,605,184
	Production	(2,004,498	)	(2,172,790	)
	Revisions of estimates	(10,074,880	)	(15,813,979	)

Balance, December 31, 2009		59,715,512		57,214,688

Our proved oil and natural gas reserves are shown below.

			For the Years Ended December 31,
			2007	2008	2009

Oil (Bbls)
	Developed		14,951,794	20,231,477	21,144,906
	Undeveloped		32,461,428	35,613,780	38,570,606

		Total	47,413,222	55,845,257	59,715,512

Natural Gas (Mcf)
	Developed		30,783,255	28,659,033	28,302,469
	Undeveloped		17,291,707	30,145,629	28,912,219

		Total	48,074,962	58,804,662	57,214,688

Total (Boe)
	Developed		20,082,337	25,007,982	25,861,985
	Undeveloped		35,343,379	40,638,052	43,389,309

		Total	55,425,716	65,646,034	69,251,294

Standardized Measure of Discounted Future Net Cash Flows

Our standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and changes in the standardized measure as described below were prepared in accordance with generally accepted accounting principles.

Future income tax expenses are calculated by applying appropriate year-end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of our oil and natural gas properties.

The standardized measure of discounted future net cash flows relating to the proved oil and natural gas reserves are shown below.

December 31,	2009			2008			2007
Future cash flows	$	3,721,873,750		$	2,391,888,946		$	4,634,645,500
Future production costs		(902,963,847	)		(716,121,604	)		(790,284,047	)
Future development costs		(543,022,875	)		(330,672,457	)		(321,485,125	)
Future income taxes		(746,548,080	)		(394,800,287	)		(1,254,982,170	)
Future net cash flows		1,529,338,948			950,294,598			2,267,894,158
10% annual discount for estimated timing of cash flows		(775,105,191	)		(489,607,688	)		(991,727,804	)
Standardized Measure of Discounted Cash Flows	$	754,233,757		$	460,686,910		$	1,276,166,354

The changes in the standardized measure of discounted future net cash flows relating to the proved oil and natural gas reserves are shown below.

	2009			2008			2007
Beginning of the year	$	460,686,910		$	1,276,166,354		$	545,439,675
Purchase of minerals in place		28,329,307			41,597,736			325,058,027
Extensions, discoveries and improved recovery, less related costs		253,485,559			129,110,323			297,610,301
Development costs incurred during the year		107,237,470			190,631,820			113,109,335
Sales of oil and gas produced, net of production costs		(110,697,316	)		(190,374,853	)		(82,949,751	)
Accretion of discount		48,058,341			131,684,244			69,291,660
Net changes in price and production costs		619,543,318			(1,526,963,575	)		592,749,069
Net change in estimated future development costs		6,550,757			(22,637,628	)		(111,175,136	)
Revision of previous quantity estimates		(447,110,784	)		293,723,576			(7,424,163	)
Revision of estimated timing of cash flows		(35,543,586	)		(409,158,356	)		(62,546,312	)
Net change in income taxes		(176,306,219	)		546,907,269			(402,996,351	)
End of the Year	$	754,233,757		$	460,686,910		$	1,276,166,354

Management’s Business Strategy Related to Properties

Our goal is to increase stockholder value by investing in oil and gas projects with attractive rates of return on capital employed. We plan to achieve this goal by exploiting and developing our existing oil and natural gas properties and pursuing acquisitions of additional properties. Specifically, we have focused, and plan to continue to focus, on the following:

Developing and Exploiting Existing Properties. We believe that there is significant value to be created by drilling the identified undeveloped opportunities on our properties. We own interests in a total of 58,092 gross (43,607 net) developed acres and operate essentially all of the net pre-tax PV10 value of our proved undeveloped reserves. In addition, as of December 31, 2009, we owned interests in approximately 13,172 gross undeveloped acres (9,879 net). We believe that our current and future cash flow will enable us to undertake the exploitation of our properties through additional drilling activities. We will closely manage our capital expenditures to our cash flow. As commodity prices change we will consider the resulting impact on our cash flow and adjust our capital expenditures accordingly, be it up or down.

Pursuing Profitable Acquisitions. We have historically pursued acquisitions of properties that we believe to have exploitation and development potential comparable to our existing inventory of drilling locations. We have developed and refined an acquisition program designed to increase reserves and complement our existing core properties. We have an experienced team of management and engineering professionals who identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties. While our emphasis in 2010 and beyond is anticipated to focus on the further development of our existing properties, we will continue to look for acquisition opportunities with existing cash flow from production and future development potential.

Controlling Costs through Efficient Operation of Existing Properties. We operate essentially 100% of the pre-tax PV10 value of our total proved reserves, which we believe enables us to better manage expenses, capital allocation and the decision-making processes related to our exploitation and exploration activities. For the year ended December 31, 2009, our oil and gas production costs per Boe averaged $6.57, our oil and gas production taxes per Boe averaged $2.73 and general and administrative costs averaged $5.68 per Boe produced.

Other Properties and Commitments

Our principal executive offices are in a company owned building in Tulsa, Oklahoma. This office building has approximately 16,000 square feet. Additionally, we own the building in Hobbs, New Mexico which serves as our primary field office. This office building has approximately 7,500 square feet. We also own an office building in Andrews, Texas for the operation of our wholly-owned subsidiary Arena Drilling Company and for use by additional Arena Resources field personnel. This office building has approximately 6,000 square feet. At December 31, 2009, we were expanding the office in Andrews by an additional 5,000 up to 11,000 square feet. Subsequent to year end the expansion was completed and the additional space will be used by Arena Resources field personnel. Lastly, we are currently leasing approximately 1,869 square feet of space in Midland, Texas. Our Midland office is maintained for the purchase of developed and undeveloped leaseholds and for land department support. We believe the office space will be adequate for our current operations as well as allowing for continued growth.

Item 3: Legal Proceedings

In the ordinary course of business, we may be, from time to time, a claimant or a defendant in various legal proceedings. We do not presently have any material litigation pending or threatened.

Item 4: Submission of Matters to a Vote of Security Holders

Our annual shareholders’ meeting was held on December 11, 2009. The shareholder’s re-elected Messrs. Stanley M. McCabe, Lloyd T. Rochford, Clayton E. Woodrum, Anthony B. Petrelli and Carl F. Fiddner as Directors with terms ending in 2010. The shareholders approved an amendment to the Company’s executive stock option plan to increase the number of shares of Common Stock that may be granted under the plan from 5,500,000 to 6,000,000. The shareholders also approved a restricted stock award plan that will use shares from that same pool available for grant as restricted stock awards. The following reflects the votes cast for each matter voted on at the annual meeting:

	Votes for	Votes against	Abstain
Lloyd T. Rochford	33,035,317	2,797,173	-
Stanley M. McCabe	27,834,068	7,998,422	-
Clayton E. Woodrum	27,820,843	8,011,647	-
Anthony B. Petrelli	33,734,756	2,097,734	-
Carl H. Fiddner	33,733,780	2,098,710	-

Amendment to stock option plan	23,285,445	9,184,761	3,362,284
Restricted stock award plan	21,516,700	10,958,283	3,357,507

PART II

Item 5:

Market for Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market for our Common Stock

Our common stock is been traded on the New York Stock Exchange, under the symbol “ARD”. The following table shows the high and low sales prices for each quarter during the last two years.

Period	High Sale		Low Sale

1st Quarter 2008	$	44.17	$	29.25
2nd Quarter 2008		57.60		38.00
3rd Quarter 2008		56.59		32.47
4th Quarter 2008		39.03		17.63

1st Quarter 2009	$	31.51	$	18.62
2nd Quarter 2009		38.04		26.03
3rd Quarter 2009		36.06		27.57
4th Quarter 2009		45.24		32.76

1st Quarter 2010 (through March 1, 2010)	$	45.06	$	38.34

Record Holders

As of February 23, 2010, there are approximately 30,521 holders of record of our common stock. As of February 23, 2010, 532,606 shares, or approximately 1.4%, of the 38,793,963 shares issued and outstanding as of such date are held by management or affiliated parties.

Dividend Policy

We have not paid any dividends on our common stock during the last three years, and we do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, our credit facility prohibits us from paying dividends.

Securities Authorized for Issuance Under Equity Compensation Plans

In March 2003, our board of directors adopted an executive stock option plan which was subsequently approved by our shareholders at our annual meeting in July 2003, and which has been subsequently amended by votes of our shareholders. Additionally, in December 2009 the shareholders approved a restricted stock award plan. Information regarding these plan and the options and stock that have been granted under this plan may be found in this Annual Report under Part III, Items 10 and 11.

Issuer Repurchases

We did not make any repurchases of our equity securities during the quarter ending December 31, 2009.

Item 6: Selected Financial Data

The selected consolidated financial information set forth below is derived from our consolidated balance sheets and statements of operations as of and for the years ended December 31, 2009, 2008, 2007, 2006 and 2005. The data set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes thereto included in this Annual Report.

	For the Year Ended December 31,
	2009			2008		2007		2006		2005
Statement of Operations Data:
Revenues	$	126,240,777		$	208,858,645	$	100,089,698	$	59,760,117	$	25,843,077
Cost of revenues		21,999,046			28,351,514		17,156,338		9,960,178		5,772,225
Realized loss (gain) on oil derivative		(14,884,846	)		4,275,330		932,361		-		-
Depreciation, depletion and amortization		8,957,641			29,789,794		17,968,062		7,900,099		2,781,504
Accretion		410,926			309,402		190,904		127,132		102,585
General and administrative		13,453,384			13,557,202		7,815,721		3,617,309		1,365,590
Net income		42,294,179			83,617,201		34,441,939		23,267,968		9,460,683

Basic income per common share	$	1.10		$	2.28	$	1.07	$	0.83	$	0.42
Diluted income per common share		1.09			2.20		1.02		0.77		0.38



	As of December 31,
		2009			2008		2007		2006		2005
Balance Sheet Data:
Current assets	$	80,655,878		$	89,530,137	$	30,823,214	$	14,674,345	$	7,673,860
Oil and gas properties subject to amortization		661,453,134			548,714,235		339,887,859		171,708,200		69,770,685
Total assets		657,554,954			591,684,775		350,980,663		176,312,978		74,421,907
Total current liabilities		18,256,893			19,789,547		19,216,475		14,995,870		6,737,806
Total long-term liabilities		116,631,301			89,599,767		73,953,223		41,273,056		8,919,826
Total Stockholders Equity		522,666,730			482,295,461		257,810,965		120,044,052		58,728,755

Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion and analysis should be read in conjunction with our accompanying financial statements and the notes to those financial statements included elsewhere in this Annual Report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this Annual Report.

Overview

We are engaged in oil and natural gas acquisition, exploration and exploitation activities in the states of Oklahoma, Texas, New Mexico and Kansas. Over the last six years, we have emphasized the acquisition of properties that provided current production and upside potential through further development.

We have increased our reserves significantly by investing approximately $111 million in acquisitions and development in 2009, following total capital expenditures of approximately $207.4 million in 2008 and $167.2 million in 2007.

We will closely manage our capital expenditures to our cash flow. As commodity prices change we will consider the resulting impact on our cash flow and adjust our capital expenditures accordingly, be it up or down. We also intend to continue seeking acquisition opportunities which compliment our current portfolio. We could draw on our credit facility or funds derived from future equity transactions for future acquisitions.

Our business plan has involved increasing our base of proven reserves until we have acquired a sufficient core to enable us to utilize cash from existing production to fund further development activities. When we originated our business plan we believed this would allow us to lessen our risks, including risks associated with borrowing funds to undertake exploration activities at an earlier time. We increased our base of proven properties and initiated development activities as oil and natural gas prices increased.

While our focus has shifted to include more development activity, we plan to continue our strategy of acquiring producing properties with additional development, exploitation and exploration potential. Our focus has been on acquiring operated properties (i.e. properties with respect to which we serve as the operator on behalf of all joint interest owners) so that we can better control the timing and implementation of capital spending.

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

In a worst case scenario, future drilling operations could be largely unsuccessful, oil and gas prices could further decline and/or other factors beyond our control could cause us to greatly modify or substantially curtail our development plans, which could negatively impact our earnings, cash flow and most likely the trading price of our securities, as well as the acceleration of debt repayment and a reduction in our borrowing base under our credit facilities.

Results of Operations

The following table sets forth selected operating data for the periods indicated:

	For the Years Ended December 31,
	2007		2008		2009

Net production:
Oil (Bbls)		1,316,025		2,018,335		2,004,498
Natural gas (Mcf)		1,503,612		1,911,713		2,172,791

Net sales:
Oil	$	88,025,225	$	190,050,617	$	115,284,731
Natural gas		12,064,473		18,808,028		10,956,046

Average sales price:
Oil (per Bbl)	$	66.82	$	94.16	$	57.51
Natural gas (per Mcf)		8.02		9.84		5.04

Production costs and expenses
Oil and gas production costs	$	11,500,461	$	17,833,144	$	15,543,461
Production taxes		5,655,877		10,518,370		6,455,585
Realized loss (gain) on oil derivative		932,361		4,275,330		(14,884,846	)
Depreciation, depletion and amortization expense		17,968,062		29,789,794		38,957,461
Accretion expense		190,904		309,402		410,926
General and administrative expenses		7,815,721		13,557,202		13,453,384

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Oil and natural gas sales. Oil and natural gas sales revenue decreased approximately $82.6 million to $126.2 million in 2009. Oil sales decreased $74.8 million and natural gas sales decreased $7.8 million. The oil sales decrease was caused by a 39% decrease in the average realized per barrel oil price from $94.16 in 2008 to $57.51 in 2009 and a reduction in sales volume of 13,837 barrels in 2009. These per barrel amounts are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels. The natural gas sales decrease was caused by a 49% decrease in the average realized per Mcf gas price from $9.84 in 2008 to $5.04 in 2009, partially offset by an increase in the sales volume of 261,078 Mcf. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The volume increase for natural gas primarily resulted from development of our existing properties in 2009.

Oil and gas production costs. Our aggregate oil and gas production costs decreased from $17,833,144 in 2008 to $15,543,461, and decreased on a Boe basis from $7.63 in 2008 to $6.57 in 2009. These per Boe amounts are calculated by dividing our total production costs by our total volume sold, in Boe. This decrease in the aggregate and on a per Boe basis was the result of lower average costs for services and equipment.

Oil and gas production taxes. Oil and gas production taxes as a percentage of oil and natural gas sales were 5.04% during 2008 and increased slightly to 5.11% in 2009. Production taxes vary from state to state. Therefore, these taxes are likely to vary in the future depending on the mix of production we generate from various states, and on the possibility that any state may raise its production tax.

Realized loss (gain) on oil derivative. Realized loss (gain) on oil derivative changed from a loss of $4,275,330 in 2008 to a gain of $14,884,846 in 2009. This change is the result of significantly lower prices for the majority of 2009 as compared to 2008.

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased by $9,269,371 to $39,368,567 in 2009. The increase was a result of an increase in the average depreciation, depletion and amortization rate from $12.88 per Boe during 2008 to $16.63 per Boe during 2009. These per Boe amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total volume sold, in Boe. The increased depreciation, depletion and amortization were the result of an increase in estimated future development costs.

General and administrative expenses. General and administrative expenses remained relatively steady, decreasing by $103,818 to $13, 452,384 during 2009. This decrease was primarily related to a decrease in compensation expense related to our stock option plan, partially offset by increases in other areas, such as insurance and taxes and fees.

Interest income. Interest income decreased $470,947 to $828,992 in 2009. The decrease was primarily due to lower interest rates between periods.

Interest expense. Interest expense decreased $1,145,456 to $0 in 2009. The decrease was due to not having any amounts outstanding on our credit facility during 2009.

Income tax expense. Our effective tax rate was 37% during 2008 and 37% during 2009.

Net income. Net income decreased from $83,617,201 for 2008 to $42,294,179 for 2009. The primary reason for this decrease was the lower average crude oil and natural gas prices received between periods.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Oil and natural gas sales. Oil and natural gas sales revenue increased approximately $108.8 million to $208.9 million in 2008. Oil sales increased $102.1 million and natural gas sales increased $6.7 million. The oil sales increase was caused by a sales volume increase of 702,310 barrels in 2008, and a 41% increase in the average realized per barrel oil price from $66.82 in 2007 to $94.16 in 2008. These per barrel amounts are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels. The natural gas sales increase was caused by a sales volume increase of 408,102 Mcf in 2008, and a 23% increase in the average realized per barrel oil price from $8.02 in 2007 to $9.84 in 2008. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The volume increase for crude oil and natural gas primarily resulted from development of our existing properties in 2008.

Oil and gas production costs. Our aggregate oil and gas production costs increased from $11,500,461 in 2007 to $17,833,144, and increased on a Boe basis from $7.34 in 2007 to $7.63 in 2008. These per Boe amounts are calculated by dividing our total production costs by our total volume sold, in Boe. This aggregate increase was the result of the drilling of new wells in 2008 and cost increases. The increase on a per Boe basis is attributable to rising rates for labor and services.

Oil and gas production taxes. Oil and gas production taxes as a percentage of oil and natural gas sales were 5.65% during 2007 and decreased to 5.04% in 2008. Production taxes vary from state to state. Therefore, these taxes are likely to vary in the future depending on the mix of production we generate from various states, and on the possibility that any state may raise its production tax.

Realized loss on oil derivative. Realized loss on oil derivative increased from $932,361 in 2007 to $4,275,330 in 2008. This increase is the result of commodity price increases during most of 2008.

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased by $11,940,230 to $30,099,196 in 2008. The increase was a result of an increase in the average depreciation, depletion and amortization rate from $11.59 per Boe during 2007 to $12.88 per Boe during 2008. These per Boe amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total volume sold, in Boe. The increased depreciation, depletion and amortization were the result of increased sales volume and an increase in estimated future development costs.

General and administrative expenses. General and administrative expenses increased by $5,741,481 to $13,557,202 during 2008. This increase was primarily related to increases in compensation expense associated with an increase in personnel required to administer our growth and compensation expense related to our stock option plan.

Interest income. Interest income increased $414,949 to $1,299,939 in 2008. The increase was due to higher cash balances during periods of the year in 2008.

Interest expense. Interest expense decreased $266,064 to $1,145,456 in 2008. The increase was due to lower amounts of debt being outstanding during periods of the year in 2008.

Income tax expense. Our effective tax rate was 37% during 2008 and 38% during 2007.

Net income. Net income increased from $34,441,939 for 2007 to $83,617,201 for 2008. The primary reasons for this increase include higher crude oil and natural gas prices between periods and an increase in volumes sold, partially offset by higher oil and gas production costs, oil and gas production taxes and general and administrative expenses due to our growth.

Liquidity and Capital Resources

Historical Financing. We have historically funded our operations through cash available from operations, and from equity offerings of our stock and warrants in 2007 and 2008.

Credit Facility. In June 2009, we entered into an amended and restated credit agreement that provides for a credit facility of $150 million with a borrowing base of $75 million with the structure in place to increase that borrowing base an additional $75 million. The new facility has an interest rate grid with a range of LIBOR plus 2.25% to 3.25%, depending upon our level of utilization of the credit facility with the total interest rate to be charged being no less than 4.00%. All other terms and conditions that existed under our prior credit facility remained the same. As of December 31, 2009, we were in compliance with all covenants and did not have any amount outstanding under this credit facility.

Cash Flows. Our primary sources of cash have been cash flows from operations and equity offerings. During the three years ended December 31, 2009, we generated $349,504,656 from operating activities and financed $222,388,933 through proceeds from the sale of stock and warrants and exercise of warrants and options. We primarily used this cash generation to fund our capital expenditures and development aggregating $497,777,217 over the three years end December 31, 2009. At December 31, 2009, we had cash on hand of $63,635,078 and working capital of $62,398,985, compared to December 31, 2008 when our cash was $58,489,574 and working capital of $69,740,590.

We continually evaluate our capital needs and compare them to our capital resources. We will closely manage our capital expenditures to our cash flow. As commodity prices change we will consider the resulting impact on our cash flow and adjust our capital expenditures accordingly, be it up or down. The level of capital expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among others.

Schedule of Contractual Obligations. The following table summarizes our future estimated lease payments for periods subsequent to December 31, 2009. This lease pertains to an office building in Midland, Texas and involves approximately 1,869 square feet of space.

Year	Lease Obligation

2010		20,715
2011		21,649
2012		22,584
2013		19,469
	$	84,417

Off-Balance Sheet Financing Arrangements

As of December 31, 2009 we had no off-balance sheet financing arrangements.

Critical Accounting Policies and Estimates

Our discussion of financial condition and results of operations is based upon the information reported in our financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. Our significant accounting policies are detailed in Note 1 to our financial statements included in this Annual Report. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.

Revenue Recognition. We predominantly derive our revenue from the sale of produced crude oil and natural gas. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received; however, differences have been insignificant.

Full Cost Method of Accounting. We account for our oil and natural gas operations using the full cost method of accounting. Under this method, all costs associated with property 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 cost of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. All of our properties are located within the continental United States.

Oil and Natural Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this Annual Report are prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of:

·	the quality and quantity of available data;

·	the interpretation of that data;

·	the accuracy of various mandated economic assumptions; and

·	the judgments of the persons preparing the estimates.

Our proved reserve information included in this Annual Report were based on internal reports and audited by Williamson Petroleum Consultants, Inc., independent petroleum engineers. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. We continually make revisions to reserve estimates throughout the year as additional properties are acquired. We make changes to depletion rates and impairment calculations in the same period that changes to the reserve estimates are made.

All capitalized costs of oil and gas properties, including estimated future costs to develop proved reserves and estimated future costs of 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.

Impairment of Oil and Natural Gas Properties. We review the value of our oil and natural gas properties whenever management judges that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. We provide for impairments on undeveloped property when we determine that the property will not be developed or a permanent impairment in value has occurred. Impairments of proved producing properties are calculated by comparing future net undiscounted cash flows using escalated prices to the net recorded book cost at the end of each period (“Ceiling test”). If the net capitalized cost exceeds net future cash flows, the cost of the property is written down to “fair value,” which is determined using net discounted future cash flows from the producing property. Current market conditions, in the form of low commodity prices, have had a dramatic effect on this calculation. The net discounted future cash flow from producing properties is directly impacted by commodity prices. Different pricing assumptions or discount rates could result in a different calculated impairment. We have never recorded property impairments as a result of the ceiling test.

Our reserve estimates as of December 31, 2009 are based on an average price of $57.628 for oil and $4.904 for gas. We have run an impairment test analysis to determine at approximately what price level impairment would result. Because our reserves are predominantly oil, at approximately 85% of total reserves, this analysis was based solely on the oil price while leaving gas prices at the levels used for preparing the reserve estimates as of December 31, 2009. Based on this analysis, our contracted oil price would have to drop below $37 per barrel for the ceiling test to result in impairment to our producing properties.

Income Taxes. Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to actual in the period we file our tax returns.

Derivative Instruments. The estimated fair values of our commodity derivative instruments are recorded in the consolidated balance sheet. At inception, all of our commodity derivative instruments represent hedges of the price of future oil and gas production. The changes in fair value of those derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative income or expense.

Our hedges are specifically referenced to NYMEX prices. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices we receive from our designated production. Through this analysis, we are able to determine if a high correlation exists between the prices received for the designated production and the NYMEX prices at which the hedges will be settled.

Effects of Inflation and Pricing

We experienced increases and decreases in costs during 2009 due to fluctuating demand for oil field products and services as a result of fluctuating oil and gas prices. The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Material changes in prices impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate business costs will vary in accordance with commodity prices for oil and natural gas, and the associated increase or decrease in demand for services related to production and exploration.

Item 7A Quantitative and Qualitative Disclosure About Market Risk

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Market risk refers to the risk of loss from adverse changes in oil and natural gas prices. Realized pricing is primarily driven by the prevailing domestic price for crude oil and spot prices applicable to the region in which we produce natural gas. Historically, prices received for oil and natural gas production have been volatile and unpredictable. We expect pricing volatility to continue. Oil prices we received during 2009 ranged from a low of $30.87 per barrel to a high of $74.81 per barrel. Natural gas prices we received during 2009 ranged from a low of $0.72 per Mcf to a high of $11.92 per Mcf. A significant decline in the prices of oil or natural gas could have a material adverse effect on our financial condition and results of operations.

As of December 31, 2009 the Company’s only derivative contracts are costless collars. 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 December 31, 2009.

Commodity	Remaining Period	Volume (Bbls)		Floor		Ceiling
WTI Crude Oil	January 2010 - December 2010		730,000	$	65.00	$	93.00
WTI Crude Oil	January 2010 - December 2010		365,000	$	70.00	$	92.85

Commodity	Remaining Period	Volume (MMBTU)		Floor		Ceiling
El Paso Permian Gas	January 2010 - December 2010		1,825,000	$	4.00	$	7.87

There were no hedges in effect as of December 31, 2009, therefore the Company did not record an asset or a liability. The after tax impact of the change in the fair value of the hedge of $10,212,601 is reflected in other comprehensive income as unrealized gain on oil derivative for the period ended December 31, 2009. 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 or loss on derivatives in the operating section of the Company’s statement of operations. Our statement of operations includes a gain on derivative instruments of $14,884,846 for 2009 and a loss on derivative instrument of $4,275,330 for 2008 and $932,361 for 2007.

Interest Rate Risk

Our current credit facility has a floating interest rate. Therefore, if we draw funds on this credit facility, interest rate changes will impact future results of operations and cash flows.

Item 8: Financial Statements and Supplementary Data

The financial statements and supplementary data required by this item are included at page 53.

Item 9: Changes in and Disagreements with Accountants And Accounting and Financial Disclosure

None.

Item 9A: Controls and Procedures

Evaluation of Disclosure Controls and Procedures.

We maintain controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submit 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. As of the end of the fiscal year ended December 31, 2009, our chief executive officer and chief financial officer evaluated the effectiveness of our disclosure controls and procedures. Based upon their evaluation of those controls and procedures, the chief executive officer and the chief financial officer of the Company concluded that as of the end of such period our disclosure controls and procedures are effective in alerting them to material information in a timely manner that is required to be included in the reports we file or submit under the Securities Exchange Act of 1934.

Management’s Annual Report on Internal Control Over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal controls over financial reporting. Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

In making our assessment of internal control over financial reporting, our management used the criteria issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on our assessment, we believe that, as of December 31, 2009, our internal control over financial reporting is effective based on those criteria.

Hansen, Barnett & Maxwell, P.C., our independent registered public accounting firm, has issued an attestation report on management’s assessment of Arena’s internal control over financial reporting.

Date: March 1, 2010

	/s/ Phillip W. Terry
	Chief Executive Officer

	/s/ William R. Broaddrick
	Chief Financial Officer

HANSEN, BARNETT & MAXWELL, P.C.

A Professional Corporation

CERTIFIED PUBLIC ACCOUNTANTS

5 Triad Center, Suite 750

Salt Lake City, UT 84180-1128

Phone: (801) 532-2200

Fax: (801) 532-7944

www.hbmcpas.com

Registered with the Public Company

Accounting Oversight Board

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

of Arena Resources, Inc.

We have audited Arena Resources, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Arena Resources, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Arena Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets and the related statements of operations and comprehensive income, stockholders’ equity, and cash flows of Arena Resources, Inc. and our report dated March 1, 2010 expressed an unqualified opinion thereon.

/s/ HANSEN, BARNETT & MAXWELL, P.C.

Salt Lake City, Utah

March 1, 2010

Changes in Internal Control Over Financial Reporting

We made no change in our internal control over financial reporting during our fourth quarter of 2009 that has materially affected, or is reasonably likely to materially affect our internal control over financial reporting.

Item 9B: Other Information

None

PART III

Item 10: Directors, Executive Officers and Corporate Governance

Executive Officers and Directors

The following table sets forth information regarding our executive officers, certain other officers and directors as of December 31, 2009:

Name	Age	Position

Lloyd T. Rochford	63	Chairman of the Board of Directors
Phillip W. Terry	62	President and Chief Executive Officer
William R. Broaddrick	32	Vice President and Chief Financial Officer
David D. Ricks	49	Vice President of Operations
Stanley M. McCabe	77	Director
Clayton E. Woodrum	69	Director
Anthony B. Petrelli	57	Director
Carl H. Fiddner	64	Director

Each of the directors identified above were elected for a term of one year (or until their successors are elected and qualified) at our annual meeting of shareholders in December 2009.

Messrs. Rochford and McCabe have served as directors since our inception in August 2000. Mr. Woodrum has served as a member of our Board since 2003. Mr. Petrelli was elected to the Board by the remaining members of the Board of Directors in January 2007 to fill the vacancy left by the death of Mr. Chris V. Kemendo, Jr. Mr. Fiddner was elected to the Board by the remaining members of the Board of Directors on May 1, 2007, to fill the vacancy left by the resignation of Charles Crawford.

The following biographies describe the business experience of our executive officers and directors:

Lloyd T. Rochford – Chairman of the Board of Directors.

Mr. Rochford, 63, has been active as an individual consultant and entrepreneur in the oil and gas industry since 1973. In this capacity, he has primarily been engaged in the organization and funding of private oil and gas drilling and completion projects and ventures within the mid-continent region of the United States. In 1990 Mr. Rochford was co-founder, director and CEO of a public company known as Magnum Petroleum, Inc. (Magnum) which was listed on the New York Stock Exchange. Subsequently, Magnum acquired Hunter Resources, Inc. in August, 1995. Mr. Rochford served as Chairman of the Board of the combined companies from August, 1995 to June, 1997. From July, 1997 until he committed to participate in Arena Resources, Mr. Rochford had primarily devoted his time and efforts to individual oil and gas acquisition and development. In 1982, Mr. Rochford was co-founder of Dana Niguel Bank, a publicly held California bank operation and served as a director until 1994. Mr. Rochford attended various college level courses in business from 1967 to 1970 in California.

Phillip W. Terry – President and Chief Executive Officer.

Mr. Terry, 62, has served as President and Chief Operating Officer since February 1, 2007 and as Chief Executive Officer since May 20, 2008. Mr. Terry joined the Company in April 2003, and since that time he has been in charge of all engineering and field operations. Immediately prior to joining the Company, Mr. Terry owned and operated an independent petroleum engineering consulting firm. The Company was one of his clients. In 2001 and 2002, Mr. Terry was Vice President of Drilling and Production for Bird Creek Resources, Inc. Mr. Terry received his Bachelor of Science degree in Mechanical Engineering from Oklahoma State University in 1970, and is a registered Professional Petroleum Engineer with over 35 years experience in engineering, production, drilling, completions, reservoir engineering, property evaluations and corporate management in the oil and gas industry.

William R. Broaddrick – Vice President and Chief Financial Officer.

Mr. Broaddrick, 32, was employed from 1997 to 2000 with Amoco Production Company, performing lease revenue accounting and state production tax regulatory reporting functions. During 2000, Mr. Broaddrick was employed by Duke Energy Field Services, LLC performing state production tax functions. In September 2001, Mr. Broaddrick joined us as chief accountant, and effective February 1, 2002, assumed responsibilities as Vice President and Chief Financial Officer.

Mr. Broaddrick received a Bachelor’s Degree in Accounting from Langston University, through Oklahoma State University – Tulsa, in 1999. Mr. Broaddrick is a Certified Public Accountant.

David D. Ricks – Vice President of Operations.

Mr. Ricks, 49, joined the Company in November 2007 as Vice President of Operations, he has over 28 years of petroleum industry experience. Mr. Ricks began his career in 1982 as a production engineer in Southeast New Mexico for Gulf Oil Co. Since then he has served in various engineering capacities for Chevron USA, Amerada Hess Corp., Citation Oil and Gas Corp., Newfield Exploration Mid-Continent, Inc., Apache Corp., and Latigo Petroleum, Inc. His duties ranged from maintaining production, designing workovers and recompletions and facility installation, to field supervision of both primary and secondary production, including waterfloods and CO2 floods, primarily in Oklahoma, North and West Texas and Southeast New Mexico.

Stanley M. McCabe –Director.

Mr. McCabe, 77, served from 1979 to 1989, as Chairman and CEO of Stanton Energy, Inc., a Tulsa, Oklahoma natural resource company specializing in contract drilling and operation of oil and gas wells. In 1990, Mr. McCabe also became a co-founder and subsequently an officer and director of Magnum Petroleum, Inc., along with Mr. Rochford as previously discussed. Subsequently, Mr. McCabe served as a director of Magnum Hunter Resources, Inc., through December, 1996. From January, 1997, until he committed to participate in Arena Resources, Mr. McCabe had primarily devoted his time and efforts to individual oil and gas acquisition and development. Mr. McCabe attended college courses at the University of Maryland, primarily in business, in 1961 and 1962.

Clayton E. Woodrum – Director.

Mr. Woodrum, 69, is a Certified Public Accountant and has, from 1984 to present, been a principal shareholder in the accounting firm of Woodrum, Kemendo, Tate & Westemeir, P.L.L.C., and has been an owner of Computer Data Litigation Services, LLC and First Capital Management, LLC. Mr. Woodrum is currently the Chairman of our audit committee and compensation committee. From 1965 to 1975, Mr. Woodrum was employed by Peat, Marwick, Mitchell & Co., serving as partner in charge of the tax department during the final two years. From 1975 to 1980 he served as CFO for BancOklahoma Corp. and Bank of Oklahoma. From 1980 to 1984 Mr. Woodrum served as a partner in charge of the tax department at Peat, Marwick, Mitchell & Co.

Anthony B. Petrelli – Director.

Mr. Petrelli, 57, was elected to the Board by the remaining members of the Board of Directors in January 2007 to fill the vacancy left by the death of Mr. Chris V. Kemendo, Jr. Since 1987 Mr. Petrelli has been with the firm of Neidiger Tucker Bruner, Inc., which firm served as one of the lead underwriters in our secondary registration of common stock in August of 2004. Mr. Petrelli is currently a Director and Senior Vice President of such firm. From August 2007 until June 2009, Mr. Petrelli also served on the Board of Directors of XLR8 Inc., which had a class of securities registered with the Securities and Exchange Commission. Also, between January 2006 and March 2007 Mr. Petrelli also served on the Board of Directors of Whitney Information Network, Inc., which has a class of securities registered with the Securities and Exchange Commission.

Carl H. Fiddner – Director.

Mr. Fiddner, 64, joined to the Board in May 2007, to fill the vacancy left by the resignation of Charles Crawford. Mr. Fiddner is a certified public accountant who managed his own public accounting firm for 25 years, prior to joining Regier, Carr & Monroe, in Tulsa, Oklahoma, in December 2005. Mr. Fiddner worked at Regier, Carr & Monroe through September 30, 2007 at which time he became an independent financial consultant.

Our executive officers are elected by, and serve at the pleasure of, our Board of Directors. Our directors serve terms of one year each, with the current directors serving until the 2010 annual meeting of stockholders, and in each case until their respective successors are duly elected and qualified.

Board Committees

Our Board of Directors has established an Audit Committee, a Compensation Committee and a Nominating and Corporate Governance Committee, the composition and responsibilities of which are briefly described below. The charters for each of these committees can be found on our website (www.arenaresourcesinc.com). We shall also provide any person without charge, upon request, a copy of the charters for each of these committees. Requests may be directed to Arena Resources, Inc., 6555 S. Lewis Ave., Tulsa, Oklahoma 74136, attention William R. Broaddrick, or by calling (918) 747-6060.

The Audit Committee’s principal functions are to assist the Board in monitoring the integrity of our financial statements, the independent auditor’s qualifications and independence, the performance of our independent auditors and our compliance with legal and regulatory requirements. The Audit Committee has the sole authority to retain and terminate our independent auditors and to approve the compensation paid to our independent auditors. The Audit Committee is also responsible for overseeing our internal audit function. During 2009, the Audit Committee was comprised of our three independent directors, Messrs. Woodrum, Petrelli and Fiddner, with Mr. Woodrum acting as the chairman. Our Board of Directors determined that both Messrs. Woodrum and Fiddner qualified as “audit committee financial experts” under the rules of the SEC adopted pursuant to requirements of the Sarbanes-Oxley Act of 2002 (see the biographical information for Messrs. Woodrum and Fiddner, infra, in this discussion of “Directors and Executive Officers”). Each of Messrs. Woodrum, Petrelli and Fiddner further qualified as “independent” in accordance with the applicable regulations adopted by the SEC and Section 303A.02 of the New York Stock Exchange Corporate Governance Standards. (see the biographical information for Messrs. Woodrum, Petrelli and Fiddner, infra, in this discussion of “Directors and Executive Officers”).

The Compensation Committee’s principal function is to make recommendations regarding the compensation of the Company’s officers. In accordance with the rules of the New York Stock Exchange, the compensation of our chief executive officer is recommended to the Board (in a proceeding in which the chief executive officer does not participate) by the Compensation Committee. Compensation for all other officers is also recommended to the Board for determination, by the Compensation Committee. During 2009, the Compensation Committee was comprised of our three independent directors, Messrs. Woodrum, Petrelli and Fiddner, with Mr. Woodrum acting as the chairman.

The Nominating and Corporate Governance Committee’s principal functions are to (a) identify and recommend qualified candidates to the Board of Directors for nomination as members of the Board and its committees, and (b) develop and recommend to the Board corporate governance principles applicable to the Company. During 2009, the Compensation Committee was comprised of our three independent directors, Messrs. Woodrum, Petrelli and Fiddner, with Mr. Woodrum acting as the chairman.

There have been no material changes to the procedures by which security holders may recommend nominees to our Board of Directors.

Our Board may establish other committees from time to time to facilitate our management.

Code of Ethics

We have adopted a code of ethics (our Code of Business Conduct) that applies to our principal executive officer, principal financial officer and principal accounting officer or persons performing similar functions (as well as our other employees and directors). The Code of Business Conduct can be found on our website (www.arenaresourcesinc.com). We shall also provide any person without charge, upon request, a copy of such Code of Business Conduct. Requests may be directed to Arena Resources, Inc., 6555 S. Lewis Ave., Tulsa, Oklahoma 74136, attention William R. Broaddrick, or by calling (918) 747-6060.

Section 16(a) Beneficial Ownership Reporting Compliance

Based solely upon a review of Forms 4 furnished to us during our most recent fiscal year, we know of no director, officer or beneficial owner of more than ten percent of our common stock who failed to file on a timely basis reports of beneficial ownership of the our common stock as required by Section 16(a) of the Securities Exchange Act of 1934, as amended, other than the following:

William R. Broaddrick (Chief Financial Officer) filed two Form 4’s late (one day each).

Lloyd T. Rochford (Chairman of the Board) filed two Form 4’s late (one day and two days).

David D. Ricks (Vice President of Operations) filed a Form 4 late (regarding the grant of 470 shares pursuant to a restricted stock grant – 13 days).

Item 11: Executive Compensation

Compensation Discussion & Analysis

This section contains a discussion of the material elements of compensation awarded to, earned by or paid to our principal executive and principal financial officers, and our other three most highly compensated executive officers and employees. These individuals are referred to as the (“Named Officers”) in this Annual Report on Form 10-K.

Our current executive compensation programs are determined and approved by our Compensation Committee, after consideration of recommendations by our Chairman of the Board and our Chief Executive Officer, as to the other Named Officers. None of the Named Officers are members of the Compensation Committee. The Compensation Committee has the direct responsibility and authority to review and approve the Company’s goals and objectives relative to the compensation of the Named Officers, and to determine and approve (either as a committee or with the other members of the Company’s Board of Directors who qualify as “independent” directors under applicable guidelines adopted by the New York Stock Exchange) the compensation levels of the Named Officers.

Our current executive compensation programs are intended to achieve two objectives. The primary objective is to enhance the profitability of the Company, and thus shareholder value. The second objective is to attract, motivate, reward and retain employees, including executive personnel, who contribute to the long-term success of the Company. As described in more detail below, the material elements of our current executive compensation program for Named Officers include a base salary, discretionary annual bonuses and discretionary stock options grants.

The Company believes that each element of the executive compensation program helps to achieve one or both of the compensation objectives outlined above. The table below lists each material element of our executive compensation program and the compensation objective or objectives that it is designed to achieve.

Compensation Element		Compensation Objectives Attempted to be Achieved

Base Salary		Attract and retain qualified executive’s Motivate and reward executives performance
Bonus Compensation		Motivate and reward executive’s performance Enhance profitability of Company and shareholder value
Equity-Based Compensation – stock options and restricted stock grants		Enhance profitability of Company and shareholder value by aligning long-term incentives with shareholders’ long-term interests

As illustrated by the table above, base salary is primarily intended to attract and retain qualified executives. This is the element of the Company’s current executive compensation program where the value of the benefit in any given year is not wholly dependent on performance. Base salaries are intended to attract and retain qualified executives as well as being linked to performance by rewarding and/or motivating executives. Base salaries are reviewed annually and take into account: experience and retention considerations; past performance; improvement in historical performance; anticipated future potential performance; and other issues specific to the individual executive.

There are specific elements of the current executive compensation program that are designed to reward performance and enhance profitability and shareholder value, and therefore the value of these benefits is based on performance. The Company’s discretionary annual bonus plan is primarily intended to motivate and reward Named Officers’ performance to achieve specific strategies and operating objectives, as well as improved financial performance.

The Compensation Committee, with input from both Messrs. McCabe and Rochford, considers the salaries of comparable executives of peer companies for which such information is publicly available. The Compensation Committee believes that bonuses and equity compensation should fluctuate with the Company’s success in achieving financial, operating and strategic goals. The Committee’s philosophy is that the Company should continue to use long-term compensation such as stock options to align shareholder and executives’ interests and should allocate a portion of long-term compensation to the entire executive compensation package.

The Company has never retained an outside consultant in establishing its compensation program or in establishing any specific compensation for an executive officer.

Current Executive Compensation Program Elements

Base Salaries

Similar to most companies within the industry, our policy is to pay Named Officers’ base salaries in cash. Effective August 1, 2009, the Compensation Committee increased salaries for Named Officers by an aggregate of $60,000. The raises were to Messrs. David R. Ricks, Thomas W. Wahl and William C. Gaines, raising Mr. Ricks individual base salary to $200,000 and raising Messrs. Wahl and Gaines individual base salaries to $150,000 each. In approving these salary increases, the Committee took into account factors including, peer group comparisons available to the Committee, each executive’s individual experience and increased responsibilities and improved performance for the Company.

Annual Bonuses

In the past, the Company has not had a formal policy regarding bonuses, and payment of bonuses has been purely discretionary and is largely based on the recommendations of the Chairman of the Board and the Chief Executive Officer (except as to themselves). In the recent past, annual bonuses have been established as a percentage of each employee’s base salary. The Compensation Committee may reduce or increase the size of the payout for each individual Named Officer at their discretion. Cash bonuses were declared and paid out in July and December of 2009 for all five of the Named Officers. Cash bonuses are not a significant portion of the executive compensation package. The annual discretionary bonus is reported in the “Bonus” column of the “Summary Compensation Table” for each Named Officer.

Perquisites

The Company currently provides a vehicle allowance for some of its employees, including two of the Named Officers. Perquisites are reported in the “All Other Compensation” column of the “Summary Compensation Table’ for each Named Officer, if applicable.

Equity-Based Compensation – Restricted Stock Grants

The Company does not have a formal policy regarding granting of restricted stock, and granting of stock is discretionary and is largely based on the recommendations of the Chairman of the Board and the Chief Executive Officer (except as to themselves). In 2009, restricted stock was granted in conjunction with the cash bonus declared and paid in December, to three of the Named Officers. Restricted stock grants are not a significant portion of the executive compensation package. The grant date fair value, as determined under generally accepted accounting principles, of the annual discretionary bonus is reported in the “Stock Grant” column of the “Summary Compensation Table” for each Named Officer.

Equity-Based Compensation - Options

It is our policy that the Named Officers’ long-term compensation should be directly linked to enhancing profitability and value provided to shareholders of the Company’s common stock. Accordingly, the Compensation Committee, (upon the recommendation of Messrs. McCabe and Rochford, with respect to grants of options other than to themselves) grants equity awards under the Company’s stock option plan designed to link an increase in shareholder value to compensation. All of the Named Officer’s equity-based compensation opportunity was awarded in the form of the Company’s non-qualified stock options. Stock option grants are valued using the Black-Scholes Model and are calculated as a part of the executive compensation package for the year based on the amount of requisite service period served. Non-qualified stock options for Named Officers and other key employees generally vest ratably over five years. The Compensation Committee believes that these awards encourage Named Officers to continue to use their best professional skills and to retain Named Officers for longer terms.

Grants are determined for Named Officers based on his or her performance in the prior year, his or her expected future contribution to the performance of the Company, and other competitive data on grant values of peer companies. Awards may be granted to new key employees or Named Officers on hire date. Other grant date determinations are made by the Compensation Committee, which is based upon the date the Committee met and proper communication was made to the Named Officer or key employee as defined in the definition of grant date by generally accepted accounting principles. Exercise prices are equal to the value of the Company’s stock on the close of business on the determined grant date. The Company has no program or practice to coordinate timing of grants with release of material, nonpublic information.

The grant date fair value as determined under generally accepted accounting principles is shown in the “Summary Compensation Table” below.

Compensation Committee’s Report on Executive Compensation (1)

Among the duties imposed on our Compensation Committee under its charter, is the direct responsibility and authority to review and approve the Company’s goals and objectives relevant to the compensation of the Company’s Chief Executive Officer and other executive officers, to evaluate the performance of such officers in accordance with the policies and principles established by the Compensation committee and to determine and approve, either as a Committee, or (as directed by the Board) with the other “independent” Board members (as defined by the New York Stock Exchange listing standards), the compensation level of the Chief Executive Officer and the other executive officers. During 2009 the Compensation Committee was composed of the three non-employee Directors named at the end of this report each of whom is “independent” as defined by the New York Stock Exchange listing standards.

The Compensation Committee has reviewed and discussed with management the disclosures contained in the Compensation Discussion and Analysis section of this Item 11. Based upon this review and our discussions, the Arena Resources, Inc. Compensation Committee recommended to its Board of Directors that the Compensation Discussion and Analysis section be included in this annual report on Form 10-K.

Compensation Committee of the Board of Directors

Clayton E. Woodrum (Chair)

Anthony B. Petrelli

Carl H. Fiddner

_____________________

(1) SEC filings sometimes “incorporate information by reference.” This means the Company is referring you to information that has previously been filed with the SEC, and that this information should be considered as part of the filing you are reading. Unless the Company specifically states otherwise, this Compensation Committee Report shall not be deemed to be incorporated by reference and shall not constitute soliciting material or otherwise be considered filed under the Securities Act of 1933 as amended, or the Securities Exchange act of 1934, as amended.

Compensation Committee’s Interlocks and Insider Participation

The Compensation Committee members whose names appear above were committee members during 2009. No member of the Compensation Committee is or has been a former or current Named Officer of the Company or had any relationships requiring disclosure by the Company under the SEC’s rules requiring disclosure of certain relationships and related-party transactions. None of our Named Officers identified herein served as a director or a member of a compensation committee (or other committee serving an equivalent function) of any other entity.

Compensation of Named Officers

The “Summary Compensation Table” set forth below should be read in connection with the tables and narrative descriptions that follow. The “Outstanding Equity Awards at Fiscal Year End Table” and “Option Exercises and Stock Vested Table” provide further information on the Named Officers’ potential realizable value and actual value realized with respect to their equity awards.

The Company does not have any pension plans, non-qualified deferred compensation plans or severance, retirement, termination, constructive termination or change in control arrangements for any of its Named Officers for the year ended December 31, 2009.

Summary Compensation Table

Name and Principal Position	Year	Salary ($)		Bonus ($)		Stock Grants (1) ($)		Option Awards (2) ($)		All Other Compensation ($)				Total ($)

Phillip W. Terry, President and	2007	$	164,167	$	16,000	$	-		3,863,309	$	12,408	(3	)		4,055,884
Chief Executive Officer	2008		250,000		25,000		-		-		20,750	(3	)		295,750
	2009		250,000		25,000		-		-		32,200	(3	)		307,200

William R. Broaddrick,	2007		89,583		9,000		-		1,557,976		1,400	(5	)		1,657,959
Vice President and	2008		100,008		10,000		-		-		4,500	(5	)		114,508
Chief Financial Officer	2009		100,008		10,000		-		-		6,000	(5	)		116,008

David R. Ricks, Vice President	2007		28,500		1,425		-		714,645		4,230	(4	)		748,800
of Operations	2008		190,072		19,000		-		915,270		27,523	(4	)		1,151,865
	2009		195,995		29,750		20,257		-		33,897	(4	)		279,899

Thomas W. Wahl,	2007		50,000		2,633		-		1,125,176		1,800	(5	)		1,179,609
Vice President of Land	2008		125,000		12,500		-		-		5,625	(5	)		143,125
	2009		142,869		15,625		15,645		-		8,572	(5	)		182,711

William C. Gaines,	2007		92,639		9,741		-		981,129		575	(5	)		1,084,084
Manager Reservoir	2008		125,000		12,500		-		-		6,000	(5	)		143,500
Engineering/Acquisitions	2009		135,417		21,875		15,645		-		9,438	(5	)		182,375

(1) See discussion of assumptions made in valuing these awards in the notes to our financial statements.

(2) See discussion of assumptions made in valuing these awards in the notes to our financial statements.

(3) All Other Compensation to Mr. Terry included cash paid as vehicle allowances of $12,000 for each year presented and $408, $8,750 and $20,200 for the years 2007, 2008 and 2009, respectively, as company matching for contributions to a 401k program.

(4) All Other Compensation to Mr. Ricks included cash paid as vehicle allowances of $2,520, $18,400 and $19,200 for the years 2007, 2008 and 2009 and $1,710, $9,123 and $14,697 for the years 2007, 2008 and 2009, respectively, as company matching for contributions to a 401k program.

(5) All Other Compensation to Messrs. Broaddrick, Wahl and Gaines consisted of company matching for contributions to a 401k program.

The Company awards stock options to key employees and the Named Officers either on the initial date of employment or due to performance incentives throughout the year. During 2009, there were no option grants to any Named Officer.

As part of annual discretionary bonus restricted stock awards were granted to three of the Named officers during 2009.

Named Officers are not separately entitled to receive dividend equivalent rights with respect to each stock option. Each nonqualified stock option award described in the “Grants of Plan-Based Awards Table” above expires six-months following the fifth anniversary of its associated grant date and vests in equal installments over the course of five years.

The following table provides certain information regarding unexercised stock options outstanding for each Named Officer as of December 31, 2009.

Outstanding Equity Awards

Name and Principal Position	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable		Options Exercise Price ($)		Option Expiration Date

Phillip W. Terry		40,000		120,000		19.23	07/22/12
		60,000		90,000		37.59	06/01/13

William R. Broaddrick		40,000		60,000		19.23	07/22/12
		20,000		30,000		37.59	06/01/13

David R. Ricks		20,000		30,000		35.54	05/07/13
		10,000		40,000		45.68	11/01/13

Thomas W. Wahl		-		60,000		26.96	01/24/13

William C. Gaines		-		60,000		23.42	12/01/12

The following table presents information regarding the exercise of stock options by Named Officers during 2009.

Option Exercises and Stock Vesting

	Option Awards
Name	Number of Shares Acquired on Exercise (#)	Value Realized on Exercise ($)
Thomas W. Wahl	20,000	63,200
William C. Gaines	27,000	277,020

Director Compensation

During all of 2009, all directors were compensated with a stipend of $1,500 per month plus $1,000 for each meeting of the directors attended. No director receives a salary as a director.

Director Compensation Table

Name	Fees Earned or Paid in Cash ($)	Option Awards ($) (1)	All Other Compensation ($)	Total ($)
Lloyd T. Rochford	22,000	-	-	22,000
Stanley M. McCabe	22,000	-	-	22,000
Clayton E. Woodrum	22,000	-	-	22,000
Anthony B. Petrelli	22,000	-	-	22,000
Carl H. Fiddner	22,000	-	-	22,000

(1) No options or awards of restricted stock were granted to any of the directors during the year ended December 31, 2009.

The following table sets forth information concerning our executive stock compensation plans as of December 31, 2009.

	Number of securities to be issued upon exercise of outstanding options		Weighted-average exercise price of outstanding options		Number of securities remaining available for future issuance under compensation plans (excluding securities in column (a))
	(a)		(b)		(c)
Equity compensation plans approved by security holders		1,895,000	$	23.87		1,294,774

Equity compensation plans not approved by security holders		-		-		-

Total		1,895,000	$	23.87		1,294,774

Item 12: Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth, as March 1, 2010, information regarding the beneficial ownership of our common stock: (i) by each of our directors and executive officers; and (ii) by all directors and executive officers as a group. The mailing address for each of the persons indicated is our corporate headquarters.

Beneficial ownership is determined under the rules of the Securities and Exchange Commission. In general, these rules attribute beneficial ownership of securities to persons who possess sole or shared voting power and/or investment power with respect to those securities and includes, among other things, securities that an individual has the right to acquire within 60 days. Unless otherwise indicated, the stockholders identified in the following table have sole voting and investment power with respect to all shares shown as beneficially owned by them.

	Shares of Common Stock Beneficially Owned
Name	Number	Percent
Lloyd T. Rochford	365,200 (1)	1%

Phillip W. Terry	230,000 (2)	1%

William R. Broaddrick	191,200 (3)	1%

David D. Ricks	30,470 (4)	*

Stanley M. McCabe	350,000 (5)	1%

Clayton E. Woodrum	20,000 (6)	*

Anthony B. Petrelli	97,000 (7)	*

Carl H. Fiddner	38,736 (8)	*

All directors and executive officers	1,322,606 (9)	3%

(1)	Includes 70,000 shares issuable upon the exercise of stock options that are currently exercisable and 80,000 shares issuable upon the exercise of stock options that are exercisable within 60 days.

(2)	Includes 100,000 shares issuable upon the exercise of stock options that are currently exercisable and 40,000 shares issuable upon the exercise of stock options that are exercisable within 60 days.

(3)	Includes 60,000 shares issuable upon the exercise of stock options that are currently exercisable and 20,000 shares issuable upon the exercise of stock options that are exercisable within 60 days.

(4)	Includes 30,000 shares issuable upon the exercise of stock options that are currently exercisable.

(5)	Includes 270,000 shares issuable upon the exercise of stock options that are currently exercisable and 80,000 shares issuable upon the exercise of stock options that are exercisable within 60 days.

(6)	Includes 10,000 shares issuable upon the exercise of stock options that are currently exercisable and 5,000 shares issuable upon the exercise of stock options that are exercisable within 60 days.

(7)	Includes 50,000 shares issuable upon the exercise of stock options that are currently exercisable and 20,000 shares issuable upon the exercise of stock options that are exercisable within 60 days.

(8)	Includes 30,000 shares issuable upon the exercise of stock options that are currently exercisable.

(9)	Includes 620,000 shares issuable upon the exercise of stock options that are currently exercisable and 245,000 shares issuable upon the exercise of stock options that are exercisable within 60 days by all executive officers and directors.

*	Represents beneficial ownership of less than 1%

The following table sets forth, as March 1, 2010, information regarding the beneficial ownership of our common stock: by all persons known to us to own 5% or more of our outstanding shares of common stock.

	Shares of Stock Beneficially Owned
Name and Address	Number	Percentage

Neuberger Berman Group, LLC 605 Third Avenue New York, New York 10158	4,285,209 (1)	11.05%

FMR LLC 82 Devonshire Street Boston, Massachusetts 02109	3,233,498 (2)	8.30%

BlackRock, Inc. 40 East 52nd Street New York, New York 10022	2,915,226 (3)	7.51%

T. Rowe Price Associates, Inc. 100 E. Pratt Street Baltimore, Maryland 21202	2,147,920 (4)	5.54%

______________________________________

(1)

This share ownership information was provided by a Schedule 13G filed February 17, 2010, which discloses that each of Neuberger Berman Group, LLC and Neuberger Berman, LLC possesses shared power to dispose or direct the disposition of 4,285,209 shares, and shared power to vote 3,562,743 shares. The Schedule 13G further discloses that Neuberger Berman Management LLC possesses shared power to vote and dispose or direct the disposition of 1,909,522 shares, and Neuberger Berman, Equity Funds possesses shared power to vote and dispose or direct the disposition of 3,403,528 shares.

(2)	This share ownership information was provided by a Schedule 13G filed February 16, 2010, which discloses that FMR LLC, possesses beneficial ownership of the reported shares.

(3)

This share ownership information was provided by a Schedule 13G filed January 29, 2010, following the acquisition by BlackRock, Inc. of Barclays Global Investors, NA; the Schedule discloses BlackRock possesses sole power to dispose or direct the disposition and sole power to vote or to direct the vote of such shares.

(4)	This share ownership information was provided by a Schedule 13G filed February 11, 2010, which discloses that T. Rowe Price Associates, Inc. possesses sole dispositive power of the reported shares.

Percentage ownership calculations for any stockholder listed above are based on 38,793,963 shares of our common stock outstanding as of March 1, 2010.

Item 13: Certain Relationships and Related Transactions, and Director Independence

In July 2002, we borrowed $200,000 from each of Messrs. Rochford and McCabe, which debts are evidenced by notes payable which matured and were paid in January 2007. The notes bore interest at a rate of 10% per annum, and were secured by our assets (although such notes were subordinate to our credit facility with our primary commercial lender).

As discussed under Item 10 of this Form 10-K, the Board of Directors has determined that Messrs. Woodrum, Petrelli and Fiddner, are each “independent” directors within the meaning of Section 303A.00 of the New York Stock Exchange Listed Company Manual. None of our independent directors falls within any of the categories of persons who would not be independent as described in Section 303A.00(b) of the New York Stock Exchange rules. Because the Board of Directors believes it is not possible to anticipate or provide for all circumstances that might give rise to conflicts of interest or that might bear on the materiality of a relationship between a director and the Company, the Board has not established specific objective criteria, apart from the criteria set forth in the New York Stock Exchange rules, to determine “independence”. In addition to such criteria, in making the determination of “independence”, the Board of Directors considers such other matters including (i) the business and non-business relationships that each independent director has or may have had with the Company and its other Directors and executive officers, (ii) the stock ownership in the Company held by each such Director, (iii) the existence of any familial relationships with any executive officer or Director of the Company, and (iv) any other relevant factors which could cause any such Director to not exercise his independent judgment.

Item 14: Principal Accountant Fees and Services

The firm of Hansen, Barnett & Maxwell, P.C., (“HBM”) has served as the Company’s independent auditors since 2000. The Audit Committee selected HBM as the independent auditors of the Company for the fiscal year ending December 31, 2009. The Audit Committee has adopted a policy that requires advance approval of all audit, audit-related, tax services and other services performed by the independent auditor.

Fees and Independence

Audit Fees. HBM billed the Company an aggregate of $124,646 and $124,062 for professional services rendered for the audit of the Company’s financial statements for the years ended December 31, 2009 and 2008, respectively, and its reviews of the Company’s financial statements included in its Form 10-Q’s for the first three quarters of 2009 and 2008.

Audit Related Fees. HBM billed the Company $0 and $37,024 for the years ended December 31, 2009 and 2008, respectively, for its services in connection with the review of the Company’s registration statements on Form S-3 and for the audit of the Phoenix Petrocorp acquisition.

Tax Fees. HBM billed the Company $5,000 for professional services rendered for tax compliance, tax advice and tax planning for each of the years ended December 31, 2009 and 2008.

All Other Fees. No other fees were billed by HBM to the Company during 2009 and 2008.

The Audit Committee of the Board of Directors has determined that the provision of services by HBM described above is compatible with maintaining HBM’s independence as the Company’s principal accountant.

Item 15: Exhibits

(a)	Financial Statements
	See Index to Financial Statements on page 54

(b)	Exhibits

3.1	Articles of Incorporation of Arena Resources, Inc. (i)

3.2	By-Laws of Arena Resources, Inc. (i)

10.1	Second Amended and Restated Credit Agreement dated as of June 30, 2009, effective as of July 2, 2009, among the Company, MidFirst Bank, Compass Bank and Capital One, N.A. (ii)

23.1	Consent of Williamson Petroleum Consultants, Inc., Independent Petroleum Engineers

23.2	Consent of Hansen, Barnett & Maxwell, P.C., Independent

31.1	Certification of CEO

31.2	Certification of CFO

32.1	Section 1350 Certification - CEO

32.2	Section 1350 Certification – CFO

99	Reserves Audit Report of Williamson Petroleum Consultants, Inc.

(i) Incorporated herein by reference to the exhibits to Arena Resources, Inc.’s Form SB-1 filed January 2, 2001 (SEC File No. 333-46164).

(ii) Incorporated herein by reference to the exhibit to Arena Resources, Inc.’s Form 8-K filed July 29, 2009.

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on behalf by the undersigned, thereunto duly authorized.

	Arena Resources, Inc.

	By:______________________
	Mr. Phillip W. Terry
	President and Chief Executive Officer

	Date: March 1, 2010

	By:______________________
	Mr. William R. Broaddrick
	Chief Financial Officer

	Date: March 1, 2010

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.

	______________________
	Mr. Lloyd T. Rochford
	Director

	Date: March 1, 2010

	______________________
	Mr. Stanley McCabe
	Director

	Date: March 1, 2010

	______________________
	Mr. Clayton E. Woodrum
	Director

	Date: March 1, 2010

	______________________
	Mr. Anthony B. Petrelli
	Director

	Date: March 1, 2010

	______________________
	Mr. Carl H. Fiddner
	Director

	Date: March 1, 2010

ARENA RESOURCES, INC.

INDEX TO FINANCIAL STATEMENTS

	Page

Report of Independent Registered Public Accounting Firm	55

Consolidated Balance Sheets	56

Consolidated Statements of Operations	57

Consolidated Statements of Stockholders’ Equity	58

Consolidated Statements of Cash Flows	59

Notes to Consolidated Financial Statements	60

Supplemental Information on Oil and Gas Producing Activities	76

HANSEN, BARNETT & MAXWELL, P.C.

A Professional Corporation

CERTIFIED PUBLIC ACCOUNTANTS

5 Triad Center, Suite 750

Salt Lake City, UT 84180-1128

Phone: (801) 532-2200

Fax: (801) 532-7944

www.hbmcpas.com

Registered with the Public Company

Accounting Oversight Board

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

of Arena Resources, Inc.

We have audited the accompanying consolidated balance sheets of Arena Resources, Inc. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations and comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Arena Resources, Inc. and subsidiaries as of December 31, 2009 and 2008, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Arena Resources, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2010 expressed an unqualified opinion thereon.

/s/ HANSEN, BARNETT & MAXWELL, P.C.

Salt Lake City, Utah

March 1, 2010

ARENA RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS


December 31,	2009			2008

ASSETS
Current Assets
Cash	$	63,635,078		$	58,489,574
Accounts receivable		13,103,483			8,637,308
Joint interest billing receivable		2,392,814			2,836,948
Receivable from oil derivative		-			2,508,396
Fair value of oil derivative		-			16,210,478
Prepaid expenses		1,040,513			847,433

Total Current Assets		80,171,888			89,530,137

Property and Equipment
Oil and gas properties subject to amortization		661,453,134			548,714,235
Oil and gas gathering systems		2,134,876			-
Inventory for property development		1,052,538			1,670,067
Drilling rigs		6,694,841			6,899,433
Land, buildings, equipment and leasehold improvements		5,991,983			5,799,045
Total Property and Equipment		677,327,372			563,082,780
Less: Accumulated depreciation , depletion and amortization		(100,428,326	)		(60,928,142	)

Net Property and Equipment		576,899,046			502,154,638

Total Assets	$	657,070,934		$	591,684,775

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	17,155,260		$	12,877,084
Current taxes payable		314,700			-
Deferred income taxes		-			6,046,508
Accrued liabilities		1,101,633			865,955

Total Current Liabilities		18,571,593			19,789,547

Long-Term Liabilities
Asset retirement liability		7,209,812			5,066,348
Deferred income taxes		108,622,799			84,533,419

Total Long-Term Liabilities		115,832,611			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;
38,693,963 shares and 38,210,187 shares outstanding, respectively		38,694			38,210
Additional paid-in capital		326,990,590			318,701,383
Retained earnings		195,637,446			153,343,267
Accumulated other comprehensive income		-			10,212,601

Total Stockholders' Equity		522,666,730			482,295,461

Total Liabilities and Stockholders' Equity	$	657,070,934		$	591,684,775

The accompanying notes are an integral part of these consolidated financial statements.

ARENA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

For the years ended December 31,	2009			2008			2007

Oil and Gas Revenues	$	126,240,777		$	208,858,645		$	100,089,698

Costs and Operating Expenses
Oil and gas production costs		15,543,461			17,833,144			11,500,461
Oil and gas production taxes		6,455,585			10,518,370			5,655,877
Realized loss (gain) on oil derivative		(14,884,846	)		4,275,330			932,361
Depreciation, depletion and amortization		38,957,641			29,789,794			17,968,062
Accretion expense		410,926			309,402			190,904
General and administrative (which includes $4,649,928, $6,586,279 and $4,140,747, respectively, in stock based compensation)		13,453,384			13,557,202			7,815,721

Total Costs and Operating Expenses		59,936,151			76,283,242			44,063,386

Income from Operations		66,304,626			132,575,403			56,026,312

Other Income (Expense)
Interest income		828,992			1,299,939			884,990
Interest expense		-			(1,145,456	)		(1,411,520	)

Net Other Income (Expense)		828,992			154,483			(526,530	)

Income Before Provision for Income Taxes		67,133,618			132,729,886			55,499,782

Provision for Income Taxes		(24,839,439	)		(49,112,685	)		(21,057,843	)

Net Income	$	42,294,179		$	83,617,201		$	34,441,939

Basic Net Income Per Common Share	$	1.10		$	2.28		$	1.07
Diluted Net Income Per Common Share		1.09			2.20			1.02

Other Comprehensive Income (Loss)
Net income	$	42,294,179		$	83,617,201		$	34,441,939
Realized loss (gain) on hedge derivative contract settlements reclassified from other comprehensive loss (income), net of tax		(10,222,546	)		12,381,887			-
Change in unrealized deferred hedging gains (losses), net of tax		9,945			632,212			(2,801,498	)

Total Comprehensive Income	$	32,081,578		$	96,631,300		$	31,640,441

The accompanying notes are an integral part of these consolidated financial statements.

ARENA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2007, 2008 AND 2009

												Accumulated
					Additional							Other			Total
	Common Stock				Paid-in			Deferred		Retained		Comprehensive			Stockholders'
	Shares		Amount		Capital			Compensation		Earnings		Income (Loss)			Equity

Balance December 31, 2006		29,337,574	$	29,338	$	84,730,586		$	-	$	35,284,127	$	-		$	120,044,052
Options exercised for cash		570,000		570		1,851,930			-		-		-			1,852,500
Warrants exercised for cash		127,126		127		540,169			-		-		-			540,295
Warrants exercised using cashless exercise provision		139,079		139		(139	)		-		-		-			-
Shares issued in property acquisition		5,000		5		204,745			-		-		-			204,750
Tax impact of option exercises		-		-		4,298,722			-		-		-			4,298,722
Issuance of common stock for cash, net		4,100,000		4,100		95,085,358			-		-		-			95,089,458
Expense related to vesting stock based compensation		-		-		4,140,747			-		-		-			4,140,747
Loss on change in fair value of oil derivative, net of tax		-		-		-			-		-		(2,801,498	)		(2,801,498	)
Net income		-		-		-			-		34,441,939		-			34,441,939
Balance December 31, 2007		34,278,779	$	34,279	$	190,852,118		$	-	$	69,726,066	$	(2,801,498	)	$	257,810,965
Options exercised for cash		1,333,000		1,333		4,689,927			-		-		-			4,691,260
Warrants exercised for cash		97,158		97		446,099			-		-		-			446,196
Issuance of common stock for cash, net		2,501,250		2,501		116,126,960			-		-		-			116,129,461
Expense related to vesting stock based compensation		-		-		6,586,279			-		-		-			6,586,279
Gain on change in fair value of oil derivative, net of tax		-		-		-			-		-		13,014,099			13,014,099
Net income		-		-		-			-		83,617,201		-			83,617,201
Balance December 31, 2008		38,210,187	$	38,210	$	318,701,383		$	-	$	153,343,267	$	10,212,601		$	482,295,461
Options exercised for cash		317,000		317		2,922,123			-		-		-			2,922,440
Warrants exercised for cash		161,550		162		717,161			-		-		-			717,323
Expense related to vesting stock based compensation		-		-		4,633,873			-		-		-			4,633,873
Restricted stock grant and vesting		5,226		5		16,050			-		-		-			16,055
Loss on change in fair value of oil derivative, net of tax		-		-		-			-		-		(10,212,601	)		(10,212,601	)
Net income		-		-		-			-		42,294,179		-			42,294,179
Balance December 31, 2009		38,693,963	$	38,694	$	326,990,590		$	-	$	195,637,446	$	-		$	522,666,730

The accompanying notes are an integral part of these consolidated financial statements.

ARENA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31,	2009			2008			2007

Cash Flows From Operating Activities
Net income	$	42,294,179		$	83,617,201		$	34,441,939
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization		38,957,641			29,789,794			17,968,062
Provision for income taxes		24,839,439			49,112,685			21,057,843
Gain on sale of equipment		-			-			(881	)
Stock based compensation		4,649,928			6,586,279			4,140,747
Accretion of asset retirement obligation		410,926			309,402			190,904
Changes in assets and liabilities:
Accounts, joint interest and oil derivative receivable		(1,513,645	)		9,835,045			(14,165,921	)
Current and deferred income taxes		-			(612,480	)		-
Prepaid expenses		(472,478	)		(714,040	)		(30,808	)
Excess tax benefits from share-based payment arrangements		-			-			(4,298,722	)
Accounts payable and accrued liabilities		4,513,854			(587,238	)		(814,999	)

Net Cash Provided by Operating Activities		113,679,844			177,336,648			58,488,164

Cash Flows from Investing Activities
Proceeds from sale of property and equipment		-			-			7,000
Proceeds from sale of oil and gas properties		-			296,800			1,915,640
Purchase and development of oil and gas properties		(103,778,202	)		(207,022,666	)		(168,582,803	)
Purchase of inventory for property development		(6,068,087	)		(1,670,067	)		-
Construction of oil and gas gathering systems		(2,134,876	)		-			-
Purchase of buildings, machinery and office equipment		(192,938	)		(1,931,517	)		(8,615,501	)

Net Cash Used in Investing Activities		(112,174,103	)		(210,327,450	)		(175,275,664	)

Cash Flows From Financing Activities
Proceeds from issuance of common stock and warrants, net of offering costs		-			116,129,461			95,089,458
Proceeds from exercise of warrants, net of offering costs		717,323			446,196			540,295
Proceeds from exercise of options		2,922,440			4,691,260			1,852,500
Excess tax benefits from share-based payment arrangements		-			-			4,298,722
Issuance of notes payable		-			11,000,000			65,700,000
Payment of notes payable		-			(46,000,000	)		(50,400,000	)

Net Cash Provided by Financing Activities		3,639,763			86,266,917			117,080,975

Net Increase in Cash		5,145,504			53,276,115			293,475

Cash at Beginning of Period		58,489,574			5,213,459			4,919,984

Cash at End of Period	$	63,635,078		$	58,489,574		$	5,213,459

For the years ended December 31,	2009		2008		2007

Supplemental Cash Flow Information
Cash paid for income taxes	$	-	$	612,480	$	-
Cash paid for interest		-		1,280,122		1,463,328

Non-Cash Investing and Financing Activities
Common stock issued for properties	$	-	$	-	$	204,750
Asset retirement obligation incurred in property acquisition and development		1,732,538		1,459,534		1,001,613
Depreciation on drilling rigs capitalized as oil and gas properties		542,543		640,977		306,133
Use of inventory in property development		6,685,616		-		-

The accompanying notes are an integral part of these consolidated financial statements.

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Nature of Operations – Arena Resources, Inc. (the “Company”) is a Nevada corporation that 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. In 2006, the Company formed two wholly owned subsidiaries, Arena Drilling Co. and ARD Production Company. The accompanying statements of operations and cash flows include the operations of the above 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. Changes in the future estimated oil and natural gas reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analysis could have a significant impact on the future results of operations.

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 Accounts Receivable – Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and accounts receivable. The Company has cash in excess of federally insured limits at December 31, 2009. The Company places its cash with a high credit quality financial institution.

Substantially all of the Company’s accounts receivable is from purchasers of oil and gas. Oil and gas sales are generally unsecured. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectable. Accordingly, no allowance for doubtful accounts has been provided. The Company also has a joint interest billing receivable. Joint interest billing receivables are collateralized by the pro rata revenue attributable to the joint interest holders and further by the interest itself.

Cash – The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

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 properties 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.

The Company records a liability in the period in which an asset retirement obligation (“ARO”) is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter this liability is accreted up to the final retirement cost. An ARO is a future expenditure related to the disposal or other retirement of certain assets. The Company’s ARO’s relate to future plugging and abandonment expenses of its oil and gas properties and related facilities disposal.

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent engineers. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Following is a table showing total depletion and depletion per barrel-of-oil-equivalent rate, by year for the years ended December 31, 2009, 2008, and 2007.

	For the Years Ended December 31,
	2009		2008		2007

Depletion	$	38,659,746	$	29,554,184	$	17,885,561
Depletion rate, per barrel-of-oil-equivalent (BOE)	$	16.34	$	12.65	$	11.42

In addition, capitalized costs less accumulated amortization and related deferred income taxes shall not exceed an amount (the full cost ceiling) equal to the sum of:

1) the present value of estimated future net revenues discounted ten percent computed in compliance with SEC guidelines;

2) plus the cost of properties not being amortized;

3) plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized;

4) less income tax effects related to differences between the book and tax basis of the properties.

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 but are only depreciated during periods during which they are in use and the depreciation is capitalized as part of oil and gas properties subject to amortization. For the year ended December 31, 2009, 2008 and 2007 the Company had depreciation of $542,543, $640,977 and $306,133, 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

Depreciation expense was $297,895, $235,609 and $62,921 for the years ended December 31, 2009, 2008 and 2007, respectively. An aggregate value of $530,000 has been attributed to the land on which the buildings sit and is not subject to depreciation.

Inventory for Property Development – Inventories consist primarily of tubular goods used in development and are stated at the lower of specific cost of each inventory item or market value.

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Revenue recognition – The Company predominantly derives its revenue from the sale of produced crude oil and natural gas. Revenue is recorded in the month the product is delivered to the purchaser. At the end of each month, the Company estimates the amount of production delivered to purchasers and the price we received. Variances between the Company’s estimated revenue and actual payment are recorded in the month the payment is received; however, differences have been insignificant.

Income Taxes – Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes. Deferred taxes are provided on differences between the tax bases of assets and liabilities and their reported amounts in the financial statements, and tax carry forwards. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes.

Earnings Per Share – Basic earnings per share is computed by dividing net income by the weighted-average number of common shares outstanding during the year. Diluted earnings per share are calculated to give effect to potentially issuable dilutive common shares.

Major Customers – During the year ended December 31, 2009, sales to three customers represented 75% 13% and 8% of total sales, respectively. At December 31, 2009, these customers made up 74%, 14% and 7% of accounts receivable, respectively. During the year ended December 31, 2008, sales to three customers represented 83% 8% and 5% of total sales, respectively. At December 31, 2008, these customers made up 84%, 9% and 5% of accounts receivable, respectively. During the year ended December 31, 2007, sales to two customers represented 83% and 11% of total sales, respectively. At December 31, 2007, these customers made up 85% and 7% of accounts receivable, respectively. The loss of any of the foregoing customers would not have a material adverse affect on the Company as there is an available market for its crude oil and natural gas production from other purchasers.

Stock-Based Employee Compensation – The Company has outstanding stock options and restricted stock grants to directors and employees, which are described more fully in Note 7. The Company accounts for its stock options and restricted stock grants in accordance with generally accepted accounting principles. The generally accepted accounting principles require the recognition of the cost of employee services received in exchange for an award of equity instruments in the financial statements and is measured based on the grant date fair value of the award. The generally accepted accounting principles also requires the stock option compensation expense to be recognized over the period during which an employee is required to provide service in exchange for the award (the vesting period).

Stock-based employee compensation incurred for the years ended December 31, 2009, 2008, and 2007 was $4,649,928, $6,586,279 and $4,140,747, respectively.

Stock-Based Compensation to Non-Employees – The Company accounts for its stock-based compensation issued to non-employees using the fair value method in accordance with generally accepted accounting principles. Under generally accepted accounting principles, stock-based compensation is determined as either the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable. The measurement date for these issuances is the earlier of the date at which a commitment for performance by the recipient to earn the equity instruments is reached or the date at which the recipient’s performance is complete.

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Derivative Instruments and Hedging Activities – Generally accepted accounting principles have established accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in the fair value resulting from ineffectiveness, as defined by generally accepted accounting principles, is recognized immediately in oil and natural gas sales. For derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent gains or losses on ineffectiveness and are reflected currently in interest expense. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are also recognized currently in earnings. See Note 11—Derivative Instruments and Hedging Activities.

New Accounting Policies – Recent SEC Rule-Making Activity. In December 2008, the SEC announced that it had approved revisions to modernize the oil and gas reserve reporting disclosures. The new disclosure requirements include provisions that:

·	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.

·	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. We have chosen not to make disclosure under these categories.

·	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.

We adopted the rules effective December 31, 2009.

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In August 2009, the FASB issued Accounting Standards Update 2009-5, “Measuring Liabilities at Fair Value” in order to provide further guidance on how to measure the fair value of a liability. The Update clarifies that, in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more prescribed techniques. We adopted the new guidance as of October 1, 2009. Adoption of the new guidance had no impact on our financial position or results of operations.

Fair Value Option Under US GAAP for fair value measurements, companies have an option to report selected financial assets and liabilities at fair value. We adopted the new guidance for optional fair value measurements as of January 1, 2008. Adoption of the new guidance had no effect on our financial position or results of operations as we made no elections to report selected financial assets or liabilities at fair value.

Derivative Instruments and Hedging Activities In March 2008, the FASB issued new standards which amended and expanded previous disclosure requirements related to derivative instruments and hedging activities. The new standards require qualitative disclosures about objectives and strategies for using derivative instruments, quantitative disclosures about fair value amounts of derivative instruments and related gains and losses, and disclosures about credit risk-related contingent features in derivative agreements. We adopted the new standards as of January 1, 2009. They provide only for enhanced disclosures, and adoption of the new standards had no impact on our financial position or results of operations. See Note 11. Derivative Instruments and Hedging Activities.

Subsequent Events In May 2009, the FASB issued new standards which establish the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. In particular, the new standards set forth:

·	the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements (through the date that the financial statements are issued or are available to be issued);

·	the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and

·	the disclosures that an entity should make about events or transactions that occurred after the balance sheet date.

We adopted the new standards as of June 30, 2009. We have evaluated subsequent events after the balance sheet date of December 31, 2009 through the time of filing with the SEC on March 1, 2010, which is the date the financial statements were issued.

Accounting Standards Codification In June 2009, the FASB established the FASB Accounting Standards Codification (Codification), which officially commenced July 1, 2009, to become the source of authoritative US GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative US GAAP for SEC registrants. Generally, the Codification is not expected to change US GAAP. All other accounting literature excluded from the Codification will be considered nonauthoritative. The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We adopted the new standards for our quarter ending September 30, 2009. All references to authoritative accounting literature are now referenced in accordance with the Codification.

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 – EARNINGS PER SHARE INFORMATION

For the years ended December 31,	2009		2008		2007
Net Income	$	42,294,179	$	83,617,201	$	34,441,939
Basic Weighted-Average Common Shares Outstanding		38,380,284		36,732,000		32,071,279
Effect of dilutive securities
Warrants		75,924		205,846		325,034
Stock options		501,737		986,251		1,271,616
Diluted Weighted-Average Common Shares Outstanding		38,957,945		37,924,097		33,667,929
Basic Income Per Common Share
Net income		1.10		2.28		1.07
Diluted Income Per Common Share
Net Income		1.09		2.20		1.02

NOTE 3 – OIL AND GAS PRODUCING ACTIVITIES

Set forth below is certain information regarding the aggregate capitalized costs of oil and gas properties and costs incurred by the Company for its oil and gas property acquisitions, development and exploration activities:

Capitalized Costs Relating to Oil and Gas Producing Activities

December 31,	2009			2008			2007
Unproved oil and gas properties	$	5,642,624		$	5,642,624		$	5,642,624
Proved oil and gas properties		655,810,510			543,071,611			334,245,235
Oil and gas gathering systems		2,134,876			-			-
Inventory for property development		1,052,538			1,670,067			-
Drilling rigs		6,694,841			6,899,433			6,254,737
Land, buildings, equipment and leasehold improvements		5,991,983			5,799,045			4,512,224
Total capitalized costs		677,327,372			563,082,780			350,654,820
Less accumulated depletion, depreciation and amortization		(100,428,326	)		(60,928,142	)		(30,497,371	)
Net Capitalized Costs	$	576,899,046		$	502,154,638		$	320,157,449


Net Costs Incurred in Oil and Gas Producing Activities

For the Years Ended December 31,		2009			2008			2007
Acquisition of proved properties (net of proceeds from property sale)		3,942,103			16,782,225			53,554,064
Acquisition of unproved properties (net of proceeds from property sale)		-			-			542,650
Exploration costs		-			-			-
Development costs		107,064,257			190,584,617			113,084,344
Total Net Costs Incurred	$	111,006,360		$	207,366,842		$	167,181,058

NOTE 4 – NOTES PAYABLE

Notes Payable – In June 2009, the Company entered into a new agreement that provides for a credit facility of $150 million with a borrowing base of $75 million with the structure in place to increase that borrowing base an additional $75 million. The new facility has an interest rate grid with a range of LIBOR plus 2.25% to 3.25%, depending upon the Company’s level of utilization of the credit facility with the total interest rate to be charged being no less than 4.00%. The Company is required under the terms of the credit facility to maintain a 5-to-1 ratio of income before interest, taxes, depreciation, depletion and amortization to interest expense, maintain a current asset to current liability ratio of 1-to-1 and a rolling four quarter maximum leverage ratio of no more than 2.5-to-1. As of December 31, 2009, the Company were in compliance with all covenants and did not have any amount outstanding under this credit facility.

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5 – ASSET RETIREMENT OBLIGATION

A reconciliation of the asset retirement obligation for the years ended December 31, 2007, 2008 and 2009 is as follows:

Balance, January 1, 2007	$	2,250,332
Liabilities incurred		1,027,945
Accretion expense		190,904
Deletion related to property divestitures		(26,332	)
Liabilities settled		(45,019	)
Balance, December 31, 2007	$	3,397,830
Liabilities incurred		1,459,534
Accretion expense		309,402
Liabilities settled		(100,418	)
Balance, December 31, 2008	$	5,066,348
Liabilities incurred		1,732,538
Accretion expense		410,926
Balance, December 31, 2009	$	7,209,812

NOTE 6 – STOCKHOLDERS’ EQUITY

The Company is authorized to issue 100,000,000 common shares, with a par value of $0.001 per share, and 10,000,000 Class “A” convertible preferred shares, with a par value of $0.001 per share.

Preferred Stock – There is no preferred stock outstanding.

Common Stock Issued in Stock Split – In September 2007, the Company’s Board of Directors authorized a 2 for 1 stock split. The split was effective to shareholders of record at the close of business on October 15, 2007. The split was in the form of a stock dividend, with one additional share distributed for every share held. The additional shares were distributed on October 26, 2007 and the Company’s stock began trading at its post-split price on October 29, 2007. Accordingly, all amounts of common stock, warrants and options have been retroactively restated throughout these financial statements to give effect to the 2 for 1 stock split.

Common Stock Issued in Offerings – In June 2007, the Company issued 4,100,000 shares of common stock, valued at $100,450,000, or $24.50 per share, in a private placement. Proceeds from the offering totaled $95,089,458, net of offering costs and expenses paid of $5,360,542.

In June 2008, the Company issued 2,501,250 shares of common stock, valued at $119,434,688, or $47.75 per share, in a public offering pursuant to a shelf registration statement. Proceeds to the Company, net of offering costs of $3,305,227, totaled $116,129,461.

Common Stock Issued from Warrant Exercises – During the year ended December 31, 2007, the Company issued 127,126 shares of common stock from the exercise of warrants for proceeds of $540,295. Of these warrants, 20,000 had an exercise price of $4.50 per share, 34,952 had an exercise price of $5.15 per share and 72,174 had an exercise price of $3.7425. Additionally, during the year ended December 31, 2007, the Company issued 134,120 shares of common stock in a cashless exercise of 145,000 warrants with an exercise price of $3.7425 per share and 4,959 shares of common stock in a cashless exercise of 5,824 warrants with an exercise price of $5.15 per share.

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During the year ended December 31, 2008, the Company issued 97,158 shares of common stock from the exercise of warrants. Of these warrants, 33,246 had an exercise price of $4.50 per share, 23,132 had an exercise price of $3.7425 per share and 40,780 had an exercise price of $5.15 per share, for total proceeds of $446,159.

During the year ended December 31, 2009, the Company issued 161,550 shares of common stock from the exercise of warrants. Of these warrants, 42,772 had an exercise price of $3.7425, 83,830 had an exercise price of $4.50 and 34,948 had an exercise price of $5.15, for total proceeds of $717,323.

Common Stock Issued from Option Exercises – During the year ended December 31, 2007, the Company issued 570,000 shares of common stock upon the exercise of options for proceeds of $1,852,500, or an average of $3.25 per share. As a result of these exercises, the Company recognized an additional tax benefit in the amount of $4,298,722, which was recorded against additional paid-in capital.

During the year ended December 31, 2008, the Company issued 1,333,000 shares of common stock from the exercise of options for proceeds of $4,691,260. Of these options, 1,140,000 had an exercise price of $1.85 per share, 60,000 had an exercise price of $2.40 per share, 20,000 had an exercise price of $4.15 per share, 20,000 had an exercise price of $13.70 per share, 40,000 had an exercise price of $19.23 per share, 33,000 had an exercise price of $23.42 per share and 20,000 had an exercise price of $26.96 per share.

During the year ended December 31, 2009, the Company issued 317,000 shares of common stock from the exercise of options for proceeds of $2,922,440. Of these options, 220,000 had an exercise price of $4.15, 20,000 had an exercise price of $10.43, 20,000 had an exercise price of $13.70, 27,000 had an exercise price of $23.42, 20,000 had an exercise price of $26.96 and 10,000 had an exercise price of $35.53.

Common Stock Issued pursuant to Restricted Stock Award Plan – On December 17, 2009, the Company issued 5,226 shares of common stock to key personnel. The shares issued are subject to a six month vesting period which ends in June 2010. The shares were valued at $43.10, based on the closing price on the date the shares were awarded. The expense associated with this issuance will be allocated ratably over the six month vesting period.

Warrants Issued – Prior to 2007 the Company issued stock purchase warrants in relation to various offerings. No purchase warrants have been issued in 2007, 2008 or 2009. However, through 2009 some of the previously issued warrants remained outstanding. During the year ended December 31, 2009, the balance of the remaining outstanding warrants was exercised.

Stock purchase warrants issued and exercised during the years ended December 31, 2009, 2008 and 2007 are summarized as follows:

	2009					2008					2007
	Warrants			Weighted-Average Exercise Price		Warrants			Weighted-Average Exercise Price		Warrants			Weighted-Average Exercise Price
Outstanding at beginning of the year		161,550		$	4.44		258,708		$	4.50		536,658		$	4.25
Issued		-			-		-			-		-			-
Expired		-			-		-			-		-			-
Exercised		(161,550	)		4.44		(97,158	)		4.59		(277,950	)		3.08
Outstanding at end of year		-		$	-		161,550		$	4.44		258,708		$	4.50

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7 – EMPLOYEE STOCK OPTIONS AND RESTRICTED STOCK AWARD PLAN

In 2003, the Company’s Board of Directors and shareholders approved and adopted a non-qualified executive stock option plan, which was subsequently amended by the shareholders. The amendments effectively increased the number of shares available under the plan to 6,000,000. Additionally, in 2009 the shareholders approved the adoption of a restricted stock award plan. Shares granted under the restricted stock award plan come from the same pool of available shares as the option plan. There are 1,294,774 shares eligible for grant, either as options or as restricted stock, at December 31, 2009.

Employee Stock Options – Following is a table reflecting the issuances during 2007 and 2008 and their related exercise prices:

Grant date	# of options		Exercise price
January 11, 2007		100,000	$	18.675
January 22, 2007		600,000		19.23
May 1, 2007		200,000		23.42
July 24, 2007		100,000		26.96
November 1, 2007		50,000		35.53
November 7, 2007		50,000		35.54
December 1, 2007		300,000		37.59
December 17, 2007		125,000		37.85
		1,525,000


Grant date	# of options		Exercise price
May 7, 2008		50,000	$	45.68
May 15, 2008		50,000		49.74
July 24, 2008		50,000		41.09
August 18, 2008		50,000		39.02
September 2, 2008		25,000		40.75
		225,000

No options were granted during 2009.

All granted options vest at the rate of 20% each year over five years beginning one year from the date granted and expire six months after the date of complete vesting. A summary of the status of the stock options as of December 31, 2009 and changes during the years ended December 31, 2009, 2008 and 2007 is as follows:

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	2009					2008					2007
	Options			Weighted-Average Exercise Price		Options			Weighted-Average Exercise Price		Options			Weighted-Average Exercise Price
Outstanding at beginning of the year		2,252,000		$	22.12		3,450,000		$	13.55		2,610,000		$	3.31
Issued		-					225,000			43.53		1,525,000			26.45
Forfeited		(40,000	)		41.09		(90,000	)		22.73		(115,000	)		3.35
Exercised		(317,000	)		9.22		(1,333,000	)		3.52		(570,000	)		3.25

Outstanding at end of year		1,895,000		$	23.87		2,252,000		$	22.12		3,450,000		$	13.55

Exercisable at end of year		705,000		$	20.96		537,000		$	13.27		1,050,000		$	2.33

Weighted average fair value of
options granted during the year				$	-				$	17.52				$	10.84

The Company uses the Black-Scholes option pricing model to calculate the fair-value of each option grant. The expected volatility is based on the historical price volatility of the Company’s common stock. We elected to use the simplified method for estimating the expected term as allowed by generally accepted accounting principles for options granted through December 31, 2008 and 2007. Under the simplified method, the expected term is equal to the midpoint between the vesting period and the contractual term of the stock option. The risk-free interest rate represents the U.S. Treasury bill rate for the expected life of the related stock options. The dividend yield represents the Company’s anticipated cash dividend over the expected life of the stock options. The following are the Black-Scholes weighted-average assumptions used for options granted during the years ended December 31, 2008 and 2007 (no options were granted during 2009):

	2008	2007

Risk free interest rate	3.14%	4.30%
Expected life	4.25 years	4.25 years
Dividend yield	-	-
Volatility	45%	47%

As of December 31, 2009, there was approximately $4,827,499 of unrecognized compensation cost related to stock options that will be recognized over a weighted average period of 2.07 years. The aggregate intrinsic value of options vested and expected to vest at December 31, 2009 was $32,337,120. The aggregate intrinsic value of options exercisable at December 31, 2009 was $15,714,850. The year end intrinsic values are based on a December 31, 2009 closing price of $43.12.

The 317,000, 1,333,000 and 570,000 options exercised during 2009, 2008 and 2007, respectively, had an aggregate intrinsic value on the date of exercise of 7,963,220, $44,715,770 and $12,122,600, respectively.

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information related to the Company’s stock options outstanding at December 31, 2009:

		Options Outstanding
Exercise price		Number Outstanding		Weighted-Average Remaining Contractual Life (in years)		Number Exercisable
	4.15		305,000		0.50		200,000
	10.425		40,000		1.30		20,000
	13.70		40,000		1.95		-
	18.675		100,000		2.53		40,000
	19.23		560,000		2.56		200,000
	23.42		140,000		2.84		20,000
	26.96		60,000		3.07		-
	35.53		40,000		3.33		10,000
	35.54		50,000		3.35		20,000
	37.59		250,000		3.42		100,000
	37.85		125,000		3.46		50,000
	39.02		50,000		3.85		10,000
	40.75		25,000		3.87		5,000
	41.09		10,000		4.07		10,000
	45.68		50,000		4.13		10,000
	49.74		50,000		4.17		10,000
			1,895,000		2.06		705,000

Any excess tax benefits from 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 is only subject to alternative minimum tax. The Company has substantial net operating losses available to carryover to future periods. Accordingly, no excess tax benefits have been recognized for the years ended December 31, 2009 or 2008.

Restricted stock grants – On December 17, 2009, the Company granted a total of 5,226 shares of stock under the Restricted Stock Award Plan. The shares were valued based on the market price of the shares on the grant date of $43.10 for an aggregate total of $225,241. These shares vest over a six month period and the Company will record the expense over that period. As of December 31, 2009, the Company showed an expense of $16,055. Unamortized deferred compensation of $209,186 will be amortized over the next six months.

The Restricted Stock Award Plan was approved by the shareholders during 2009, therefore no shares were issued under the plan prior to 2009. Additionally, no shares vested during any of the years 2009, 2008 or 2007.

NOTE 8 – RELATED PARTY TRANSACTIONS

In July 2002, the Company borrowed $400,000 from two of its officers under the terms of secured, 10% promissory notes. These notes and all accrued interest were paid during 2007.

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9 – COMMITMENTS

Standby Letters of Credit – A commercial bank has issued standby letters of credit on behalf of the Company to the states of Texas, Oklahoma and New Mexico totaling $686,969 to allow the Company to do business in those states. 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.

Operating leases – Effective August 20, 2008, the Company entered into a lease agreement for office space in Midland, Texas. The lease is for approximately 1,869 square feet and is for five years commencing November 2008. The Company incurred lease expense of $19,780 and $3,271 for the years ended December 31, 2009 and 2008, respectively. The following table reflects the future minimum lease payments under the operating lease as of December 31, 2009.

Year	Lease Obligation

2010		20,715
2011		21,649
2012		22,584
2013		19,469
	$	84,417

NOTE 10 – INCOME TAXES

At December 31, 2009, the Company calculated alternative minimum income tax of $798,690 of which $314,700 is currently payable, due to a previous overpayment. At December 31, 2008, the Company had no alternative minimum income tax due and had no current tax liability. The provision for income taxes consisted of the following:

Provision for income taxes	2009			2008		2007
Current	$	4,661,395		$	-	$	-
Minimum tax		798,690					539,793
Benefit of net operating loss		(4,661,395	)
Deferred		24,040,749			49,112,685		20,518,050
	$	24,839,439		$	49,112,685	$	21,057,843

The following is a reconciliation of income taxes computed using the U.S. federal statutory rate to the provision for income taxes:

Rate Reconciliation	2009		2008			2007
Tax at federal statutory rate (34%)	$	22,825,430	$	45,128,161		$	18,869,926
Non-deductible expenses		-		29,406			13,939
State tax, net of federal benefit		2,014,009		4,380,086			1,831,493
Other		-		(424,968	)		342,485
	$	24,839,439	$	49,112,685		$	21,057,843

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2009, the Company had net operating loss carry forwards for federal income tax reporting purposes of approximately $75 million which, if unused, will expire in 2026, 2027 and 2028. The Company has minimum tax credits of $1,765,774 which do not expire.

The net deferred tax liability consisted of the following:

Deferred taxes:	2009		2008		2007
Deferred tax liabilities
Current unrealized gain on oil derivative	$	-	$	6,046,508	$	-
Property and equipment		124,200,047		107,316,108		63,011,335
Total deferred tax liabilities		124,200,047		113,362,616		63,011,335

Deferred tax assets
Stock-based compensation		5,243,557		3,953,790		1,808,770
Minimum tax credit		1,765,774		967,084		862,000
Unrealized loss on oil derivative		-		-		1,658,665
Operating loss and IDC carryforwards		8,567,917		17,861,815		24,785,172
Total deferred tax assets		15,577,248		22,782,689		29,114,607
Net deferred income tax liability	$	108,622,799	$	90,579,927	$	33,896,728

Accounting for Uncertainty in Income Taxes In accordance with generally accepted accounting principles, the Company has analyzed its filing positions in all jurisdictions where it is required to file income tax returns for the open tax years in such jurisdictions. The Company has identified its federal income tax return and its state income tax returns in Texas, New Mexico, Oklahoma and Kansas in which it operates as “major” tax jurisdictions. The Company’s federal income tax returns for the years ended December 31, 2006 through 2008 remain subject to examination. The Company’s income tax returns in major state income tax jurisdictions remain subject to examination for years ended December 31, 2006 through 2008, with the exception of Texas, which would also include the year ended December 31, 2005. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon audit. Therefore, the Company has no significant reserves for uncertain tax positions and no adjustments to such reserves were required by generally accepted accounting principles. No interest or penalties have been levied against the Company and none are anticipated, therefore interest or penalty has been included in our provision for income taxes in the consolidated statements of operations.

NOTE 11 – DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Under generally accepted accounting principles, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. Instruments qualifying for hedge accounting treatment are recorded as an asset or liability measured at fair value and subsequent changes in fair value are recognized in equity through other comprehensive income, net of related taxes, to the extent the hedge is effective. The Company’s derivative instrument qualified for hedge accounting for all periods presented. The change in fair value of the derivative instrument was recorded to other comprehensive income for the years ended December 31, 2007, 2008 and 2009. The cash settlements of cash flow hedges are recorded in the operating section of the Company’s statement of operations. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet at fair value and changes in fair value are recognized on the statement of operations.

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company’s hedges are specifically referenced to NYMEX prices. The effectiveness of hedges is evaluated at the time the contracts are entered into, as well as periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices received from the designated production. Through this analysis, the Company is able to determine if a high correlation exists between the prices received for its designated production and the NYMEX prices at which the hedges will be settled. At December 31, 2007, 2008 and 2009, the Company’s hedging contracts were considered effective cash flow hedges.

The statement of operations includes a realized gain on derivative instruments of $14,884,846 for 2009 and a realized loss on derivative instruments of $4,275,330 and $932,361 for 2008 and 2007, respectively.

As of December 31, 2009, the Company had entered into the following costless collar contracts accounted for as a cash flow hedge:

Commodity	Remaining Period	Volume (Bbls)		Floor		Ceiling
WTI Crude Oil	January 2010 - December 2010		730,000	$	65.00	$	93.00
WTI Crude Oil	January 2010 - December 2010		365,000	$	70.00	$	92.85

Commodity	Remaining Period	Volume (MMBTU)		Floor		Ceiling
El Paso Permian Gas	January 2010 - December 2010		1,825,000	$	4.00	$	7.87

There were no hedges in effect as of December 31, 2009, therefore the Company did not record an asset or a liability. The fair value of the 2010 hedges is zero as of December 31, 2009, as the relative price curve for the index prices used is between the floor and the ceiling.

NOTE 12 – FAIR VALUE MEASUREMENTS

Generally accepted accounting principles establish 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 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.

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 fair value of all hedge instruments was zero as of December 31, 2009, therefore the Company does not have either an asset or a liability recorded in connection with those instruments.

NOTE 13 –EMPLOYEES’ BENEFIT PLANS

The Company’s employees are eligible to participate in a 401(k) plan after attaining the age of 21. Participants may defer up to 100% of eligible compensation. The Company matches participant contributions dollar for dollar up to 6% of participant compensation not exceeding $16,500 per employee ($22,000 for those over 50, choosing to catch-up). For the year ended December 31, 2009, 2008 and 2007, the Company made contributions to the plan totaling 290,695, $311,825 and $68,743, respectively.

NOTE 14 – QUARTERLY FINANCIAL DATA (UNAUDITED)

Quarterly financial information is presented in the following summary:

	2007
	Three Months Ended
	March 31		June 30		September 30		December 31
Revenues	$	16,651,301	$	21,620,299	$	26,731,699	$	35,086,399
Operating Income		9,395,863		13,283,378		17,661,615		15,685,456
Net Income		5,707,890		7,899,378		11,403,777		9,430,894
Basic Net Income Per Share	$	0.19	$	0.26	$	0.33	$	0.28
Diluted Net Income Per Share		0.18		0.24		0.32		0.26

	2008
	Three Months Ended
	March 31		June 30		September 30		December 31
Revenues	$	45,312,392	$	62,159,281	$	68,412,686	$	32,974,286
Operating Income		29,650,936		39,637,781		42,188,778		21,097,908
Net Income		18,318,395		24,794,349		26,922,966		13,581,491
Basic Net Income Per Share	$	0.52	$	0.69	$	0.71	$	0.36
Diluted Net Income Per Share		0.51		0.67		0.69		0.35

	2009
	Three Months Ended
	March 31		June 30		September 30		December 31
Revenues	$	20,193,160	$	27,636,695	$	36,060,878	$	42,350,044
Operating Income		9,998,248		22,702,454		18,954,179		14,649,746
Net Income		6,465,449		14,436,065		12,113,026		9,279,639
Basic Net Income Per Share	$	0.17	$	0.38	$	0.32	$	0.24
Diluted Net Income Per Share		0.17		0.37		0.31		0.24

The net income per share information above will not match the income statement due to rounding.

ARENA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 15 – SIGNIFICANT FOURTH QUARTER ADJUSTMENTS

There were no material fourth quarter adjustments or accounting changes.

NOTE 16 – SUBSEQUENT EVENTS

Subsequent to December 31, 2009, the Company issued a total of 75,000 shares of stock pursuant to the restricted stock award plan. These shares were valued based on the market price of the shares of $45.05 on the date of grant of January 6, 2010. These shares will vest 50% per year for two years and the fair value of these shares will be expensed over that period.

We have evaluated subsequent events after the balance sheet date of December 31, 2009 through the time of filing with the SEC on March 1, 2010, which is the date the financial statements were issued.

ARENA RESOURCES, INC.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

(Unaudited)

Results of Operations from Oil and Gas Producing Activities – The Company’s results of operations from oil and gas producing activities exclude interest expense, gain from change in fair value of put options, and other financing expense. Income taxes are based on statutory tax rates, reflecting allowable deductions.

For the Years Ended December 31,	2009			2008			2007
Oil and gas revenues	$	126,240,777		$	208,858,645		$	100,089,698
Production costs		(15,543,461	)		(17,833,144	)		(11,500,461	)
Production taxes		(6,455,585	)		(10,518,370	)		(5,655,877	)
Realized loss on oil derivative		14,884,846			(4,275,330	)		(932,361	)
Depreciation, depletion, amortization and accretion		(39,368,567	)		(30,099,196	)		(18,158,966	)
General and administrative (exclusive of corporate overhead)		(3,804,383	)		(3,034,525	)		(3,011,753	)
Results of operations before income taxes		75,953,627			143,098,080			60,830,280
Provision for income taxes		(28,102,842	)		(52,946,290	)		(22,507,204	)
Results of Oil and Gas Producing Operations	$	47,850,785		$	90,151,790		$	38,323,076

Recent SEC and FASB Rule-Making Activity -- In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. See Note 1 Organization and Summary of Significant Accounting Policies – New Accounting Policies. We adopted the rules effective December 31, 2009 and the rule changes, including those related to pricing and technology, are included in our reserves estimates. The new rule does not allow for prior-year reserve information to be restated, so all information related to periods prior to 2009 is presented consistent with prior SEC rules for the estimation of proved reserves.

In addition, in January 2010 the FASB issued Accounting Standards Update 2010-03, "Oil and Gas Reserve Estimation and Disclosures", to provide consistency with the SEC rules. See Note 1 Organization and Summary of Significant Accounting Policies – New Accounting Policies.

Reserve Quantities Information – The following estimates of proved and proved developed reserve quantities and related standardized measure of discounted net cash flow are estimates only, and do not purport to reflect realizable values or fair market values of the Company’s reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. All of the Company’s reserves are located in the United States of America.

Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and methods.

The standardized measure of discounted future net cash flows is computed by applying the price according to the SEC guidelines for oil and gas to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows.

ARENA RESOURCES, INC.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

(Unaudited)

For the Years Ended December 31,	2009						2008						2007
	Oil (1)			Gas (1)			Oil (1)			Gas (1)			Oil (1)			Gas (1)
Proved Developed and Undeveloped Reserves
Beginning of year		55,845,257			58,804,662			47,413,322			48,074,962			36,064,273			42,424,199
Purchases of minerals in place		1,589,141			2,791,611			3,638,095			2,364,908			7,021,972			4,330,246
Improved recovery and extensions		14,360,492			13,605,184			9,547,981			11,391,853			6,016,660			6,852,346
Production		(2,004,498	)		(2,172,790	)		(2,018,335	)		(1,911,713	)		(1,316,023	)		(1,503,611	)
Revision of previous estimate		(10,074,880	)		(15,813,979	)		(2,735,806	)		(1,115,348	)		(373,560	)		(4,028,218	)
End of year		59,715,512			57,214,688			55,845,257			58,804,662			47,413,322			48,074,962
Proved Developed at end of year		21,144,906			28,302,469			20,231,477			28,659,033			14,951,794			30,783,255

1 Oil reserves are stated in barrels; gas reserves are stated in thousand cubic feet.

Standardized Measure of Discounted Cash Flows

December 31,	2009			2008			2007
Future cash flows	$	3,721,873,750		$	2,391,888,946		$	4,634,645,500
Future production costs		(902,963,847	)		(716,121,604	)		(790,284,047	)
Future development costs		(543,022,875	)		(330,672,457	)		(321,485,125	)
Future income taxes		(746,548,080	)		(394,800,287	)		(1,254,982,170	)
Future net cash flows		1,529,338,948			950,294,598			2,267,894,158
10% annual discount for estimated timing of cash flows		(775,105,191	)		(489,607,688	)		(991,727,804	)
Standardized Measure of Discounted Cash Flows	$	754,233,757		$	460,686,910		$	1,276,166,354

Changes in Standardized Measure of Discounted Future Net Cash Flows

	2009			2008			2007
Beginning of the year	$	460,686,910		$	1,276,166,354		$	545,439,675
Purchase of minerals in place		28,329,307			41,597,736			325,058,027
Extensions, discoveries and improved recovery, less related costs		253,485,559			129,110,323			297,610,301
Development costs incurred during the year		107,237,470			190,631,820			113,109,335
Sales of oil and gas produced, net of production costs		(110,697,316	)		(190,374,853	)		(82,949,751	)
Accretion of discount		48,058,341			131,684,244			69,291,660
Net changes in price and production costs		619,543,318			(1,526,963,575	)		592,749,069
Net change in estimated future development costs		6,550,757			(22,637,628	)		(111,175,136	)
Revision of previous quantity estimates		(447,110,784	)		293,723,576			(7,424,163	)
Revision of estimated timing of cash flows		(35,543,586	)		(409,158,356	)		(62,546,312	)
Net change in income taxes		(176,306,219	)		546,907,269			(402,996,351	)
End of the Year	$	754,233,757		$	460,686,910		$	1,276,166,354