10-K

United States Securities and Exchange Commission
Washington, D.C. 20549

Form 10-K

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

	For the fiscal year ended December 31, 2006
	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)

4920 South Lewis Avenue, Suite 107 Tulsa, Oklahoma		74105
(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 |_| No |X|

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 |X|

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 |X| No |_|

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. |X|

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

Large accelerated filer |_|

Accelerated filer |X|

Non-accelerated filer |_|

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

As of June 30, 2006, the aggregate market value of the common voting stock held by non-affiliates of the issuer, based upon the closing stock price of $34.29 per share, was approximately $500,690,750.

As of March 27, 2007, the issuer had outstanding 14,821,263 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	15
Item 2	Properties	15
Item 3	Legal Proceedings	25
Item 4	Submission of Matters to a Vote of Security Holders	26
PART II
Item 5	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
Item 6	Selected Financial Data	28
Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
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 Accountant's on Accounting and Financial Disclosure	36
Item 9A	Controls and Procedures	36
Item 9B	Other Information	38
PART III
Item 10	Directors, Executive Officers and Corporate Governance	39
Item 11	Executive Compensation	43
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	49
Item 13	Certain Relationships and Related Transactions, and Director Independence	50
Item 14	Principal Accounting Fees and Services	50
PART IV
Item 15	Exhibits	51

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 4920 South Lewis Avenue, Suite 107, Tulsa, Oklahoma 74105, and our telephone number is (918) 747-6060. On or about June 1, 2007, we will be moving to our new executive offices located at 6555 South Lewis Avenue, Tulsa, Oklahoma 74136. Our telephone number will remain the same. 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

Since our inception in August 2000, we have built our asset base and achieved growth primarily through property acquisitions. From our inception through December 31, 2006, we have increased our proved reserves to approximately 43.1 million Boe (barrel of oil equivalent). As of December 31, 2006, our estimated proved reserves had a pre-tax PV10 (present value of future net revenues before income taxes discounted at 10%) of approximately $848 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $545 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 $162 million on acquisitions and capital projects during 2004, 2005 and 2006.

We have a portfolio of oil and natural gas reserves, with approximately 84% of our proved reserves consisting of oil and approximately 16% consisting of natural gas. Of those reserves approximately 28% of our proved reserves are classified as proved developed producing, or “PDP,” approximately 5% of our proved reserves are classified as proved developed non-producing, or “PDNP,” approximately 5% are classified as proved developed behind pipe “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. The majority of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which 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 our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to 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

Current competitive factors in the domestic oil and gas industry are unique. The actual price range of crude oil is largely established by major international producers. Pricing for natural gas is more regional. Because the current domestic demand for oil and gas exceeds supply, we believe there is little risk that all current production will not be sold at relatively fixed prices. To this extent we do not believe we are directly competitive with other producers, nor is there any significant risk that we could not 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. However, more favorable prices can usually be negotiated for larger quantities of oil and/or gas product. In this respect, while we believe we have a price disadvantage when compared to larger producers, we view our primary pricing risk to be related to a potential decline in international prices to a level which could render our current production uneconomical.

We are presently committed to use the services of the existing gathering companies in our present areas of production. This 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).

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 2006, sales to one customer, Navajo Refining Company, represented 82% of oil and gas revenues. At December 31, 2006, this customer represented 80% of our accounts receivable. However, we believe that the loss of this customer would not materially impact our business, because we could readily find other purchasers for our oil and gas as produced.

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 recently 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 us or our acquired properties are involved 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, 2006, we had fifty-two full-time employees, including twenty-three 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 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;

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

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

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the level of global oil and natural gas inventories;

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weather conditions;

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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 non-producing (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 39% of our proven reserves depend upon secondary recovery techniques to establish production.

Approximately thirty-nine percent (39%) of our reserves for the year ended December 31, 2006 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:

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delays imposed by or resulting from compliance with regulatory requirements;

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pressure or irregularities in geological formations;

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shortages of or delays in obtaining equipment and qualified personnel;

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equipment failures or accidents;

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adverse weather conditions;

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reductions in oil and natural gas prices;

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title problems; and

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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:

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the amount of recoverable reserves;

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future oil and natural gas prices;

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estimates of operating costs;

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estimates of future development costs;

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

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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.

If oil and natural gas prices decrease, we may be required 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:

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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;

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abnormally pressured formations;

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

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fires and explosions;

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personal injuries and death; and

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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:

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discharge permits for drilling operations;

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drilling bonds;

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reports concerning operations;

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the spacing of wells;

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unitization and pooling of properties; and

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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 $65 million. As of March 27, 2007, we had $35,500,000 outstanding on our credit facility. If in the future we further utilize this facility, the level of our indebtedness could affect our operations in several ways, including the following:

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

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

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

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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.

The loss of senior management could adversely affect us.

To a large extent, we depend on the services of our senior management. The loss of our senior management — Stanley McCabe, our Chairman, or Tim Rochford, our Chief Executive Officer — could have a material adverse effect on our operations. While we have obtained a key man life insurance policy on Mr. Rochford, any amounts that we may recover under such policy may not adequately compensate us for the loss of the services of Mr. Rochford. We do not have employment agreements with either Mr. McCabe or Mr. Rochford.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.

With the recent increase in the prices of oil and natural gas, we have encountered an increase in the cost of securing drilling rigs, equipment and supplies. Shortages or the high cost of drilling rigs, equipment, supplies and personnel are expected to continue in the near-term. In addition, larger producers may be more likely to secure access to such equipment by virtue of offering drilling companies more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, not only would this potentially delay our ability to convert our reserves into cash flow, but could also significantly increase the cost of producing those reserves, thereby negatively impacting anticipated net income.

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.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to compete.

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which 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 our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to 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. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

Risks Relating to Our Common Stock

The market price of our stock may be affected by low volume float

While there has been a public market for our common stock on the New York Stock Exchange (and, prior to August 31, 2006, on the American Stock Exchange), in the last twelve months the daily trading volume, or “public float”, of our common stock has ranged from as low as 67,700 shares to as high as 796,500 shares. The average volume of shares traded during the 90 days prior to December 31, 2006 was 1,200,200 shares per week.

Additionally, approximately 538,170 shares of our common stock are “restricted” shares under Rule 144, but could be currently sold with little difficulty under the provisions of Rule 144(k). We also estimate that approximately 448,423 additional shares of common stock that are currently “restricted”, will soon be capable of being resold under Rule 144.

Finally, as of December 31, 2006 there are warrants outstanding to purchase 268,329 shares of common stock, as well as options to purchase 1,305,000 shares of common stock (of which options to acquire 515,000 shares are currently exercisable, with 575,000 options vesting over the next two years, and the balance vesting over the next four and one-half years).

Substantial sales of our common stock, including shares issued upon the exercise of outstanding options and warrants, in the public market, or the perception that these sales could occur, may have a depressive effect on the market price of our common stock. Such sales or the perception of such sales could also impair our ability to raise capital or make acquisitions through the issuance of 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

Since our inception in late August 2000, we have begun to build a solid asset base and achieved steady growth, primarily through property acquisitions, but with some exploitation activities. From our inception through December 31, 2006, our proved reserves have grown to 43,134,974 Boe, at an average acquisition/drilling cost of $3.75 per Boe. Many properties contain both oil and gas reserves. In those cases, the oil and gas reserves and the volume of oil and gas produced are converted to a common unit of measure on the basis of their approximate relative energy content. The common unit which we use is “Barrels of oil equivalent” or “Boe.” Acquisition and drilling costs “per Boe” is calculated by dividing the net capitalized costs ($161,638,633), computed in accordance with applicable accounting standards, as shown under “Capitalized Costs Relating to Oil and Gas Producing Activities” under Supplemental Information on Oil and Gas Producing Activities, by our reserves in Boe (43,134,974).

As of December 31, 2006, our estimated proved reserves had a pre-tax PV10 value of approximately $848 million and a Standardized Measure of Discounted Future Cash Flows of approximately $545 million, approximately 25% of which came from properties located in New Mexico, approximately 64% from our properties in Texas, approximately 8% from our properties in Oklahoma and approximately 3% from our properties in Kansas. We spent approximately $162 million on capital projects during 2004, 2005 and 2006. We expect to further develop these properties through additional drilling. Our capital budget for 2007 is approximately $95 million for development of existing properties. Although our focus will be on development of our existing properties, we also intend to continue seeking acquisition opportunities which compliment our current portfolio. We intend to fund our development activity primarily through use of cash flow from operations and cash on hand, while potential drawings on our credit facility and proceeds from future equity transactions would also be available for development projects or future acquisitions. We believe that our acquisition expertise, together with our operating experience and efficient cost structure, provides us with the potential to continue our growth.

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, 2006.

Geographic Area				Pre-Tax PV10 Value		Standardized Measure of Discounted Future Net Cash Flows

New Mexico	9,481,520	6,719,361	10,601,414	$	215,443,250	$	138,359,941
Texas	23,198,670	28,048,664	27,873,447		550,485,150		354,194,438
Oklahoma	3,384,083	288,340	3,432,140		71,120,164		45,315,245
Kansas	-	7,367,834	1,227,973		10,685,624		7,570,051

Total	36,064,273	42,424,199	43,134,974	$	847,734,188	$	545,439,675

Proved Reserves

Our 43,134,974 Boe of proved reserves, which consist of approximately 84% oil and 16% natural gas, are summarized below as of December 31, 2006, 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, 2006, New Mexico proved reserves had a net pre-tax PV10 value of $215.4 million and Standardized Measure of Discounted Future Net Cash Flows of $138.4 million, our proved reserves in Texas had a net pre-tax PV10 value of $550.5 million and Standardized Measure of Discounted Future Net Cash Flows of $354.2 million, our proved reserves in Oklahoma had a net pre-tax PV10 value of $71.1 million and a Standardized Measure of Discounted Future Net Cash Flows of $45.3 million and our proved reserves in Kansas had a net pre-tax PV10 value of $10.7 million and a Standardized Measure of Discounted Future Net Cash Flows of $7.6 million.

As of December 31, 2006, approximately 28% of the 43.1 million Boe of proved reserves have been classified as proved developed producing, or “PDP”. Proved developed non-producing, or “PDNP” reserves constitute approximately 5%, proved developed behind-pipe “PDBP” reserves constitute approximately 5% and proved undeveloped, or “PUD”, reserves constitute approximately 62%, of the proved reserves as of December 31, 2006.

Total proved reserves had a net pre-tax PV10 value as of December 31, 2006 of approximately $848 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $545 million, 28.2% or $212.0 million and $136.6, respectively, of which is associated with the PDP reserves. An additional $57.2 million and $37.0 million, respectively, is associated with the PDNP reserves and $25.2 million and $16.2 million, respectively, is associated with PDBP reserves ($294.4 million and $189.8 million, respectively, for total proved developed reserves, or 38.3% of total proved reserves’ pre-tax PV10 value). The remaining $553.2 million and $355.7 million, respectively, is associated with PUD reserves.

Our proved reserves as of December 31, 2006 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		Future Capital Expenditures (In thousands)
New Mexico:
PDP	4,203,816	5,318,472	5,090,228	12%	$	83,502	$	53,626	$	-
PUD	5,277,704	1,400,889	5,511,186	13%		131,942		84,734		16,412

Total Proved:	9,481,520	6,719,361	10,601,414	25%	$	215,444	$	138,360	$	16,412

Texas:
PDP	5,439,397	4,526,690	6,193,845	14%	$	118,367	$	76,160	$	500
PDNP	1,106,705	519,315	1,193,258	3%		40,157		25,838		4,337
PDBP	-	13,701,830	2,283,638	5%		25,197		16,212		4,140
PUD	16,652,568	9,300,829	18,202,706	42%		366,765		235,985		115,313

Total Proved:	23,198,670	28,048,664	27,873,447	64%	$	550,486	$	354,195	$	124,290

Oklahoma:
PDP	379,118	70,068	390,796	1%	$	5,827	$	3,713	$	500
PDNP	437,149	89,073	451,995	1%		13,230		8,430		150
PUD	2,567,816	129,199	2,589,349	6%		52,061		33,172		7,400

Total Proved:	3,384,083	288,340	3,432,140	8%	$	71,118	$	45,315	$	8,050

Kansas:
PDP	-	2,903,815	483,969	1%	$	4,349	$	3,081	$	739
PDNP	-	2,550,711	425,119	1%		3,811		2,700		463
PUD	-	1,913,308	318,885	1%		2,526		1,789		600

Total Proved:	-	7,367,834	1,227,973	3%	$	10,686	$	7,570	$	1,802

Total:
PDP	10,022,331	12,819,045	12,158,839	28%	$	212,045	$	136,580	$	1,739
PDNP	1,543,854	3,159,099	2,070,371	5%		57,198		36,968		4,950
PDBP	-	13,701,830	2,283,638	5%		25,197		16,212		4,140
PUD	24,498,088	12,744,225	26,622,126	62%		553,294		355,680		139,725

Total Proved:	36,064,273	42,424,199	43,134,974	100%	$	847,734	$	545,440	$	150,554

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 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

2007	14,730,658	8,433,660	16,136,267	$	69,558,837
2008	9,383,280	4,052,637	10,058,719		65,372,000
2009	384,150	257,928	427,138		4,794,500

	24,498,088	12,744,225	26,622,124	$	139,725,337

Production

Our estimated average daily production for the month of December, 2006, is summarized below. These tables indicate the percentage of our estimated December 2006 average daily production of 3,700 Boe/d attributable to each state and to oil versus natural gas production.

State	Average Daily Production	Oil	Natural Gas
Texas	74.00%	64.65%	9.35%
New Mexico	20.24%	16.63%	3.61%
Oklahoma	3.09%	2.85%	0.24%
Kansas	2.67%	0.00%	2.67%

Total	100%	84.13%	15.87%

Summary of Oil and Natural Gas Properties and Projects

Significant New Mexico Operations

East Hobbs Unit – Lea County, New Mexico. In May 2004 we acquired an 82.24% working interest and a 67.6% net revenue interest in this lease. “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. This lease covers approximately 920 acres. There are currently 34 producing wells. We believe this property can support two additional wells, which are included in our estimate of PUD. This lease is held by production.

Seven Rivers Queen Unit – Lea County, New Mexico. We acquired a 70.6% working interest and a 56.48% net revenue interest in this property in May 2003. The remaining working interest is owned by unaffiliated parties. There are currently 51 producing wells on this lease. This lease consists of approximately 2,240 acres and is held by production.

North Benson Queen Unit – Eddy County, New Mexico. In October 2003 we acquired a 100% working interest and a 78.15% net revenue interest in this lease, which currently has 21 producing wells. The lease covers approximately 1,800 acres, and we believe this property can support a number of additional wells, 23 of which are included in our estimate of PUD. This lease is held by production.

The North Benson Queen Unit Waterflood expansion project is in progress. A water line of approximately four miles in length has been constructed along with the associated water storage and transfer equipment. Water injection and pumping equipment have been constructed and water injection will begin into seven wells on the west side of the property in April, 2007. Oil treating and storage facilities are being upgraded and will be completed in the third quarter of 2007. The costs for the expansion and development of the North Benson Queen Unit are estimated to be $4,450,000 in 2007. The North Benson Queen Unit waterflood expansion project will be completed in 2008 with the drilling of twenty-three (23) producing wells at an estimated cost of $9,200,000.

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. These leases cover approximately 11,300 acres. We believe this property can support a number of additional wells, 121 of which are included in our estimate of PUD. These leases are held by production.

Fuhrman-Mascho offset leases — Throughout 2005 and 2006, the Company has acquired working interests in additional leases and leased additional acreage in and around our Fuhrman-Mascho leases. The working interest percentages acquired range from 20% to 100% with net revenue interest ranging from 16% to 80%. These leases cover approximately 5,960 acres. We believe this property can support a number of additional wells, 90 of which are included in our estimate of PUD. These leases are held by production.

Y6 Lease – Fisher County, Texas. We acquired a 100% working interest and an 80% net revenue interest in this lease in June 2001. There are currently 12 producing wells on this lease. A portion of this property has been waterflooded, and when we begin our future development operations on this property, we plan to waterflood the remaining acreage. 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. This potential waterflood project (and the estimated $2,700,000 cost thereof) is included as PUD in our reserve report. This lease consists of approximately 1,697 acres and is held by production.

Significant Oklahoma Operations

Ona Morrow Sand Unit – Cimarron and Texas Counties, Oklahoma. We own a 100% working interest and an 81.32% net revenue interest in this lease which has been producing since our acquisition in July 2002. This lease has approximately 2,120 acres and 12 producing wells. We believe this property can support three additional wells, which are included in our estimate of our PUD. This lease is held by production.

Eva South Morrow Sand Unit – Texas County, Oklahoma. We own a 100% working interest and an 85.41% net revenue interest in this lease which was also acquired in July 2002. The lease consists of approximately 489 acres and has eight producing wells. We believe this property can support two additional wells, which have been included in our estimate of our PUD. This lease is held by production.

Midwell, Appleby, Smaltz and Hanes Leases – Cimarron County, Oklahoma. We own 100% of the working interest and an 80% net revenue interest in these four leases acquired in September 2002. All have been producing leases since the date of our acquisition. The Midwell Appleby and Smaltz leases consist of approximately 1,640 acres with eight producing wells, and we believe there are up to six additional drilling locations on these leases. The Hanes lease contains approximately 640 acres and two producing wells. We believe this property can support four additional wells, which are included in our estimate of PUD. All of these leases are held by production.

Roy Hanes Lease – Texas County, Oklahoma. We own a 24.5% working interest and a 21.44% net revenue interest in this lease, which is a property operated by XTO Energy, Inc, an unaffiliated company, who also owns the remaining working interest. The interest in this lease was acquired at the same time we acquired our interests in the Midwell, Appleby, Smaltz and Hanes leases, and there has been production on this lease since that time. This lease consists of approximately 640 acres, and is currently held by production.

Significant Kansas Operations

Koehn/Rexford Unit – Haskell & Gray County, Kansas. This lease consists of approximately 640 acres. After entering into a farmout agreement with Bird Creek Resources, Inc., an unaffiliated company, we drilled and completed an initial gas well on this lease. Under the terms of this agreement, we agreed to drill one well and could drill additional wells on the property. In exchange for each well drilled, we will be assigned 100% of the working interest (80% of the net revenue interest) in the well and related oil and gas until payout of all costs of drilling, equipping and operating the well. After payout, our working interest in the wells and related oil and gas will decrease to 75% (60% of the net revenue interest).

Two wells have been drilled on this acreage and they have not yet reached payout. They are anticipated to reach payout during the second quarter 2007. After payout, Bird Creek Resources, Inc. will own the remaining 25% working interest.

Schmidt Unit – Gray County, Kansas. During 2004 and 2006 we leased 10,160 acres offsetting our Koehn/Rexford Unit. We have drilled a total of 10 wells on this acreage, seven of which have been successful and have been put into production. This lease is held by production.

Syracuse Prospect – Hamilton County, Kansas. During 2005 and 2006 we leased 21,733 acres. These leases provide us a 100% working interest and an 81% net revenue interest. We have drilled a total of five wells on this acreage, two of which were successful and are in the completion phase.

Rocky Prospect – Comanche County, Kansas. During 2005 we leased 4,160 acres. These leases provide us a 100% working interest and an 80% net revenue interest. We have drilled four wells on this acreage, one of which has been successful and has been put into production.

Acreage

The following table summarizes gross and net developed and undeveloped acreage at December 31, 2006 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	4,960	3,294	--	--	4,960	3,294

Texas	20,927	15,871	--	--	20,927	15,871

Oklahoma	5,529	4,122	--	--	5,529	4,122

Kansas	13,040	10,432	15,787	12,746	28,827	23,178

Total	44,456	33,719	15,787	12,746	60,243	46,465

Production History

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

	Year Ended December 31,
		2004		2005		2006

Oil production (Bbls)		195,166		441,995		900,614
Natural gas production (Mcf)		169,002		398,611		989,991
Total production (Boe)		223,333		508,430		1,065,613
Daily production (Boe/d)		612		1,393		2,919
Average sales price:
Oil (per Bbl)	$	39.25	$	52.41	$	59.26
Natural gas (per Mcf)		4.86		6.72		6.46
Total (per Boe)		37.98		50.83		56.08
Average production cost (per Boe)	$	8.85	$	7.54	$	6.06

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, 2006, 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	106	68	-	-	106	68
Texas	395	298	-	-	395	298
Oklahoma	30	25	-	-	30	25
Kansas	-	-	10	8	10	8

Total	531	391	10	8	541	399

Drilling Activity

During 2006 we completed the drilling of 124 wells. Eighty-seven wells were drilled on our Fuhrman Mascho properties in Andrews County, Texas. Nineteen wells were drilled in Lea County, New Mexico, with fourteen on our Seven Rivers Queen property and five of them on our East Hobbs property. Twelve wells were drilled in Kansas, four in Gray County, Kansas, offsetting our existing wells there and nine in Hamilton and Greeley County, Kansas on acreage acquired during 2005; the eight wells in Hamilton and Greeley Counties were exploratory wells. Three wells were drilled in Texas County, Oklahoma, with one well on our Eva South property and two wells on our Ona Morrow property. Three wells were drilled on our Midwell and Hanes properties in Cimarron County, Oklahoma.

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 $8.85 in 2004, $7.54 in 2005 and $6.06 in 2006. These amounts are calculated by dividing our total production costs by our total volume sold, in Boe.

Costs incurred for property acquisition, exploration and development activities during the years ended December 31, 2004, 2005 and 2006 are shown below.

	For the Years Ended December 31,

		2004		2005 ⁽¹⁾		2006

Acquisition of proved properties	$	21,706,166	$	1,406,588	$	7,122,176
Acquisition of unproved properties		43,082		(160,454)		3,282,635
Exploration costs		216,805		464,656		1,124,556
Development costs		4,027,754		32,557,989		89,797,285

Total Costs Incurred	$	25,993,807	$	34,268,779	$	101,326,652

⁽¹⁾ The amount shown for 2005 for acquisition of unproved properties is net of proceeds received for partial working interests sold in wells drilled in Kansas.

Reserve Quantity Information

Our estimates of proved reserves and related valuations were based on reports prepared by Lee Keeling and Associates, Inc., independent petroleum and geological engineers, in accordance with the provisions of SFAS 69, “Disclosures About Oil and Gas Producing Activities.” 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.

		Oil (Bbls)	Natural Gas (Mcf)

Balance, December 31, 2003		7,050,167	3,408,754
	Purchase of minerals in place	8,764,087	6,431,437
	Extensions and discoveries	-	640,000
	Production	(195,167)	(169,002)
	Revisions of estimates	3,931,577	(311,648)


Balance, December 31, 2004		19,550,664	9,999,541
	Purchase of minerals in place	882,460	377,179
	Extensions and discoveries	2,546,477	19,188,896
	Production	(441,995)	(398,611)
	Revisions of estimates	2,329,583	2,815,074


Balance, December 31, 2005		24,867,189	31,982,079
	Purchase of minerals in place	3,644,144	2,605,212
	Extensions and discoveries	8,952,460	10,206,642
	Production	(900,616)	(989,991)
	Revisions of estimates	(498,904)	(1,379,743)


Balance, December 31, 2006		36,064,273	42,424,199

Our proved oil and natural gas reserves are shown below.

		For the Years Ended December 31,
		2004	2005	2006

Oil (Bbls)
	Developed	4,721,293	7,885,115	11,566,185
	Undeveloped	14,829,371	16,982,074	24,498,088

	Total	19,550,664	24,867,189	36,064,273


Natural Gas (Mcf)
	Developed	4,615,265	22,480,279	29,679,974
	Undeveloped	5,384,276	9,501,800	12,744,225

	Total	9,999,541	31,982,079	42,424,199


Total (Boe)
	Developed	5,490,504	11,631,829	16,512,848
	Undeveloped	15,726,750	18,565,707	26,622,126

	Total	21,217,254	30,197,536	43,134,974

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 the provisions of SFAS 69. Future cash inflows were computed by applying year-end prices to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in producing and developing the proved oil and natural gas reserves at year end, based on year-end costs and assuming continuation of existing economic conditions.

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 percent 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,*		2006		2005		2004

Future cash flows	$	2,206,997,329	$	1,629,948,750	$	814,346,791
Future production costs		(436,830,228)		(281,685,991)		(171,518,828)
Future development costs		(150,553,635)		(95,765,594)		(61,975,106)
Future income taxes		(578,112,324)		(423,161,523)		(187,392,403)

Future net cash flows		1,041,501,142		829,335,642		393,460,454
10% annual discount for estimated timing of cash flows		(496,061,467)		(383,735,076)		(188,219,704)

Standardized Measure of Discounted Cash Flows	$	545,439,675	$	445,600,566	$	205,240,750

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

*For the Years Ended December 31,*		2006		2005		2004

Beginning of the year	$	445,600,566	$	205,240,750	$	45,006,097
Purchase of minerals in place		18,153,711		33,405,120		142,824,938
Extensions, discoveries and improved recovery, less related costs		-		5,962,820		347,652
Development costs incurred during the year		328,401,017		189,832,736		5,387,638
Sales of oil and gas produced, net of production costs		(53,324,929)		(21,991,034)		(5,876,333)
Accretion of discount		58,727,964		28,467,073		4,882,064
Net changes in price and production costs		(106,369,988)		191,917,618		74,777,221
Net change in estimated future development costs		(53,640,718)		(36,307,702)		(3,187,159)
Revision of previous quantity estimates		(14,276,840)		87,175,031		42,149,044
Revision of estimated timing of cash flows		(8,582,606)		(111,387,288)		(27,509,967)
Net change in income taxes		(69,248,502)		(126,714,558)		(73,560,445)

End of the Year	$	545,439,675	$	445,600,566	$	205,240,750

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 44,456 gross (33,720 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, 2006, we owned interests in approximately 15,787 gross undeveloped acres (12,746 net). We believe that our current and future cash flow will enable us to undertake the exploitation of our properties through additional drilling activities. Our expected capital budget for development of existing properties in 2007 is approximately $95 million.

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 2007 and beyond is anticipated to focus on the further development of our existing properties, we will continue to look for properties with both 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, 2006, our oil and gas production costs per Boe averaged $6.06 and general and administrative costs averaged $3.39 per Boe produced.

Other Properties and Commitments

We currently lease our principal executive offices in Tulsa, Oklahoma. At December 31, 2006, the lease was for approximately 3,224 square feet of office space, at an annual rental of $30,000. This lease expired December 31, 2006 and is continuing on a month to month basis at the same rate.

On March 1, 2007, we closed the acquisition of a two story office building, and an adjoining parcel of real estate, located on 6555 South Lewis Avenue in Tulsa, Oklahoma. This office building has approximately 16,000 square feet, and we intend to occupy approximately 12,000 square feet to house our executive offices. The remaining 4,000 square feet are currently under lease to an unrelated tenant. We anticipate moving into our new executive offices in June, 2007. These facilities are believed adequate for our current operations.

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 litigation pending or threatened.

Item 4:

Submission of Matters to a Vote of Security Holders

Our annual shareholders’ meeting was held on December 7, 2006. The shareholder’s re-elected Messrs. Stanley M. McCabe, Lloyd T. Rochford, Charles M. Crawford, Chris V. Kemendo, Jr. and Clayton E. Woodrum as Directors with terms ending in 2007. The shareholders further 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 2,000,000 to 2,500,000. The following reflects the votes cast for each matter voted on at the annual meeting:

	Votes for	Votes against	Abstain

Lloyd T. Rochford	12,194,756	-	495,127
Stanley M. McCabe	12,032,841	-	657,042
Charles M. Crawford	12,214,061	-	475,822
Chris V. Kemendo, Jr.	12,106,295	-	583,588
Clayton E. Woodrum	11,964,901	-	724,982

Amendment to stock option plan	5,804,600	3,025,721	28,294

PART II

Item 5:

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

Market for our Common Stock

Since August 31, 2006, our common stock has been traded on the New York Stock Exchange, under the symbol “ARD”. Prior to that dating back to April 15, 2003, our common stock traded on the American Stock Exchange, also under the symbol “ARD.” The following table shows the high and low sales prices for each quarter during the last three years.

Period		High Sale		Low Sale
1st Quarter 2004	$	7.08	$	5.85
2nd Quarter 2004		9.65		6.98
3rd Quarter 2004		7.46		5.98
4th Quarter 2004		8.79		6.80

1st Quarter 2005	$	15.05	$	7.89
2nd Quarter 2005		13.95		9.20
3rd Quarter 2005		26.20		11.35
4th Quarter 2005		29.40		19.46

1st Quarter 2006	$	36.99	$	25.71
2nd Quarter 2006		38.60		25.88
3rd Quarter 2006		41.32		26.09
4th Quarter 2006		47.70		29.60

1st Quarter 2007 (through March 27, 2007)	$	49.42	$	37.26

Record Holders

As of March 2, 2007, there are approximately 5,116 holders of record of our common stock. As of March 27, 2007, approximately 13%, or 1,940,300 shares of the 14,821,263 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 was amended by our shareholders at our annual meetings in 2004, 2005 and 2006. Information regarding this plan and the options that have been granted under this plan may be found in this Annual Report under Part III, Items 10 and 11.

Recent Sales of Unregistered Securities

During the three months ended December 31, 2006, we issued 10,200 shares of our common stock as finder’s fees relating to property acquisitions. These shares were issued in a transaction not involving a public offering and were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act of 1933. The persons to whom the shares were issued had access to full information concerning us and represented that he acquired the shares for his own account and not for the purpose of distribution. The certificates for the shares contain a restrictive legend advising that the shares may not be offered for sale, sold or otherwise transferred without having first been registered under the 1933 Act or pursuant to an exemption from registration under the 1933 Act. There was no underwriter involved in these transactions.

Issuer Repurchases

We did not make any repurchases of our equity securities during the quarter ending December 31, 2006.

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, 2006, 2005, 2004, 2003, and 2002. 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,

	2006		2005		2004		2003		2002

Statement of Operations Data:
Revenues	$	59,760,117	$	25,843,077	$	8,482,130	$	3,665,477	$	1,657,037
Cost of revenues		9,960,178		5,772,225		2,605,538		1,418,699		712,027
Depreciation, depletion and amortization		7,900,099		2,781,504		1,011,602		360,282		127,847
Accretion		127,132		102,585		53,729		322,212		-
General and administrative		3,617,309		1,365,590		874,850		778,774		248,018
Net income		23,267,968		9,460,683		2,451,652		670,143		402,694
Preferred stock dividends		-		-		-		-		798,018
Income (Loss) attributable to common shareholders		23,267,968		9,460,683		2,451,652		670,143		(395,324)

Basic income (loss) per common share	$	1.65	$	0.85	$	0.31	$	0.10	$	(0.09)
Diluted income (loss) per common share		1.55		0.75		0.28		0.09		(0.09)

	As of December 31,

	2006		2005		2004		2003		2002

Balance Sheet Data:
Current assets	$	14,674,345	$	7,673,860	$	2,498,423	$	1,519,755	$	1,224,979
Oil and gas properties subject to amortization		171,708,200		69,770,685		34,457,137		8,463,400		4,884,804
Total assets		176,312,978		74,421,907		36,377,524		9,973,256		6,050,493
Total current liabilities		14,995,870		6,737,806		1,840,665		250,867		287,859
Total long-term liabilities		41,273,056		8,919,826		13,735,016		1,582,116		637,797
Total Stockholders Equity		120,044,052		58,728,755		20,801,843		8,140,273		5,124,837

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 $101.3 million in acquisitions and enhancements in 2006, following total capital expenditures of approximately $34.3 million in 2005 and $26 million in 2004.

Our capital budget for 2007 is approximately $95 million for development of existing properties. We also intend to continue seeking acquisition opportunities which compliment our current portfolio. We intend to fund our development activity primarily through use of cash flow from operations and cash on hand, while potential drawings on our credit facility and proceeds from future equity transactions would also be available for development projects or 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. As we have now increased our base of proven properties, and as oil and natural gas prices have recently significantly risen, we have initiated our development activities.

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. In addition, our willingness to acquire non-operated properties in new geographic regions may provide us with geophysical and geologic data in some cases that leads to further acquisitions in the same region, whether on an operated or non-operated basis.

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 sharply 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,

			2004		2005		2006

Net production:
	Oil (Bbls)		195,166		441,995		900,614
	Natural gas (Mcf)		169,002		398,611		989,991

Net sales:
	Oil	$	7,661,006	$	23,165,109	$	53,367,118
	Natural gas		821,124		2,677,968		6,392,999

Average sales price:
	Oil (per Bbl)	$	39.25	$	52.41	$	59.26
	Natural gas (per Mcf)		4.86		6.72		6.46

Production costs and expenses
	Oil and gas production costs	$	1,975,835	$	3,832,486	$	6,453,831
	Production taxes		629,703		1,939,739		3,506,347
	Depreciation, depletion and amortization expense		1,011,602		2,781,504		7,900,099
	Accretion expense		53,729		102,585		127,132
	General and administrative expenses		874,850		1,365,590		3,617,309

Year Ended December 31, 2006 Compared to Year Ended December 31, 2005

Oil and natural gas sales. Oil and natural gas sales revenue increased approximately $33.92 million to $59.76 million in 2006. Oil sales increased $30.20 million and natural gas sales increased $3.72 million. The oil sales increase was caused by a sales volume increase of 458,619 barrels in 2006, and a 13% increase in the average realized per barrel oil price from $52.41 in 2005 to $59.26 in 2006. 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 591,380 Mcf in 2006 partially offset by a 4% decrease in the average realized natural gas price per Mcf from $6.72 in 2005 to $6.46 in 2006. 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 2006.

Oil and gas production costs. Our aggregate oil and gas production costs increased from $3,832,486 in 2005 to $6,453,831, although such expenses on a Boe basis declined from $7.54 in 2005 to $6.06 in 2006. 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 2006 and cost increases. The decline on a per Boe basis is attributable to an increase in volume as a result of our development and consolidation of resources available due to our growth.

Oil and gas production taxes. Oil and gas production taxes as a percentage of oil and natural gas sales were 7.51% during 2005 and decreased to 5.87% in 2006. 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.

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased by $5,118,595 to $7,900,099 in 2006. The increase was a result of an increase in the average depreciation, depletion and amortization rate from $5.47 per Boe during 2005 to $7.41 per Boe during 2006. 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 was the result of increased sales volume and an increase in estimated future development costs.

General and administrative expenses. General and administrative expenses increased by $2,257,719 to $3,617,309 during 2006. 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 the company’s option plan as a result of adoption of FASB 123(R).

Other Financing expense. Other financing expense was $785,598 in 2006, compared to $597,773 in 2005. The increase is a result of the stock price being higher on the date of the expense in 2006 than it was on the date of the expense in 2005.

Interest expense. Interest expense decreased $104,791 to $124,833 in 2006. The decrease was due to lower amounts of debt being outstanding during periods of the year in 2006 as well as partial offset by interest income received on excess cash on hand during parts of the year.

Income tax expense. Our effective tax rate was 38% during 2006 and 37% during 2005.

Net income. Net income increased from $9,460,683 for 2005 to $23,267,968 for 2006. The primary reasons for this increase include higher crude oil prices between periods and an increase in volumes sold, partially offset by lower natural gas prices between periods and higher oil and gas production costs, oil and gas production taxes and general and administrative expenses due to our growth.

Year Ended December 31, 2005 Compared to Year Ended December 31, 2004

Oil and natural gas sales. Oil and natural gas sales revenue increased approximately $17.36 million to $25.84 million in 2005. Oil sales increased $15.50 million and natural gas sales increased $1.86 million. The oil sales increase was caused by a sales volume increase of 246,829 barrels in 2005, and a 34% increase in the average realized per barrel oil price from $39.25 in 2004 to $52.41 in 2005. 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 229,609 Mcf in 2005 and a 38% increase in the average realized natural gas price per Mcf from $4.86 in 2004 to $6.72 in 2005. 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 acquisitions made in 2004 and development of our existing properties in 2005.

Oil and gas production costs. Our aggregate oil and gas production costs increased from $1,975,835 in 2004 to $3,832,486, although such expenses on a Boe basis declined from $8.85 in 2004 to $7.54 in 2005. 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 having the properties acquired in 2004 in our operations for a full year in 2005, and the drilling of new wells in 2005 and cost increases. The decline on a per Boe basis is attributable to consolidation of resources available due to our growth.

Oil and gas production taxes. Oil and gas production taxes as a percentage of oil and natural gas sales were 7.42% during 2004 and increased to 7.51% in 2005. 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.

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased by $1,769,902 to $2,781,504 in 2005. The increase was a result of an increase in the average depreciation, depletion and amortization rate from $4.53 per Boe during 2004 to $5.47 per Boe during 2005. 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 was the result of increased sales volume and an increase in estimated future development costs.

General and administrative expenses. General and administrative expenses increased by $490,740 to $1,365,590 during 2005. This increase was primarily related to increases in compensation expense associated with an increase in personnel required to administer our growth.

Other Financing expense. Other financing expense was $597,773 in 2005, compared to $0 in 2004. The increase is a result of the offering that occurred in 2005.

Interest expense. Interest expense increased $73,688 to $229,624 in 2005. The increase was due to higher amounts of debt being outstanding during periods of the year in 2005.

Income tax expense. Our effective tax rate was 37% during 2005 and 37% during 2004.

Net income. Net income increased from $2,451,652 for 2004 to $9,460,683 for 2005. 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 loans from our executive officers and private equity offerings of our stock and warrants in 2005 and 2006 and our secondary offering of common stock and warrants which we closed in August 2004.

Credit Facility. On April 14, 2004, the Company established a credit facility with our principal lenders. In April 2005, the Company entered into an agreement that increased its credit facility to $50,000,000, with an increased borrowing base of $35,000,000. The interest rate was a floating rate equal to the 30, 60 or 90 day LIBOR rate plus 2.25%, and is payable monthly. Amounts borrowed under the revolving credit facility are due in May 2009. The revolving credit facility is secured by the Company’s principal mineral interests. The bank credit facility is subject to borrowing base availability, which is redetermined semiannually based on the banks’ estimates of the future net cash flows of our oil and natural gas properties. In order to obtain the revolving credit facility, loans from two officers were subordinated to the position of the bank. The Company is required under the terms of the credit facility to maintain a tangible net worth of $12,000,000, maintain a 5-to-1 ratio of income before interest, taxes, depreciation, depletion and amortization to interest expense and maintain a current asset to current liability ratio of 1-to-1.

In April 2006, the Company entered into a new credit agreement increasing the Company’s credit facility to $150,000,000 with a $65,000,000 borrowing base. Additionally, this new agreement adjusted the interest rate to be equal to the 30, 60 or 90 day LIBOR rate plus 2%, removed the requirement to maintain a tangible net worth but added a requirement to a rolling four quarter basis of a maximum leverage ratio of no more than 2.5-to-1. All other conditions of the credit facility remained the same. At December 31, 2006, $19,300,000 was outstanding under this credit facility, with an additional $527,500 reserved under the revolving credit facility as collateral for standby letters of credit issued to various states.

Cash Flows. Our primary sources of cash have been cash flows from operations and equity offerings. During the three years ended December 31, 2006, we generated $73,929,685 from operating activities, financed $66,728,119 through proceeds from the sale of stock and warrants and exercise of warrants and options and financed a net $19,300,000 from our outstanding credit facility. We primarily used this cash generation to fund our capital expenditures and development aggregating $137,044,529 over the three years. At December 31, 2006, we had cash on hand of $4,919,984 and a working capital deficit of $321,525, compared to December 31, 2005 when our cash was $4,317,114 and working capital of $1,083,664.

We continually evaluate our capital needs and compare them to our capital resources. Our budgeted capital expenditures for 2007 are approximately $95,000,000 for development of our current properties. We expect to fund these expenditures as well as any future property acquisitions from cash on hand, internally generated cash flow during the year 2007, proceeds from future equity transactions and from borrowings under our credit facility, if required. 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. With the exception of the credit facility and notes to officers, the Company had no future estimated principal and minimum debt and lease payments for periods subsequent to December 31, 2006.

Off-Balance Sheet Financing Arrangements

As of December 31, 2006 we had no off-balance sheet financing arrangements.

New Accounting Policies

In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 changes the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes”, and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Additionally, FIN 48 provides guidance on subsequent derecognition of tax positions, financial statement classification, recognition of interest and penalties, accounting in interim periods, and disclosure and transition requirements. FIN 48 is effective for the Company’s fiscal year beginning January 1, 2007, with early adoption permitted. The Company is in the process of evaluating FIN 48 but does not believe that its implementation will have a material effect on the Company’s financial position or results of operation in any period.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“FAS 157”). FAS 157 defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosure requirements related to the use of fair value measures in financial statements. FAS 157 will be effective for our financial statements for the fiscal year beginning January 1, 2008; however, earlier application is encouraged. We are currently evaluating the timing of adoption and the impact that adoption might have on our financial position or results of operations.

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 is based on estimates prepared by Lee Keeling and Associates, 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 on a field-by-field basis using escalated prices to the net recorded book cost at the end of each period. 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. Different pricing assumptions or discount rates could result in a different calculated impairment. We have never recorded any property impairments.

Income Taxes. We provide for income taxes in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for 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.

Effects of Inflation and Pricing

As in 2005, we did experience continued increases in costs during 2006 due to increased demand for oil field products and services. 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, and this proved to be the case in 2006 as oil and gas prices rose significantly. Costs for oilfield services and materials increased during 2006 due to higher demand as a result of the higher oil and gas prices. 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 the increased business costs will continue while the commodity prices for oil and natural gas, and the demand for services related to production and exploration, both remain high (from an historical context) in the near term.

Item 7A

Quantitative and Qualitative Disclosure About Market Risk

Commodity Price Risk

We have not historically entered into derivative contracts to manage our exposure to oil and natural gas price volatility. Normal hedging arrangements have the effect of locking in for specified periods the prices we would receive for the volumes and commodity to which the hedge relates. Consequently, while hedges are designed to decrease exposure to price decreases, they also have the effect of limiting the benefit of price increases.

Interest Rate Risk

Our current credit facility has a floating interest rate. Therefore, as a result of our draws 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 55.

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, 2006, 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 principal 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, 2006, 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 29, 2007

/s/ Lloyd T. Rochford
Chief Executive Officer

/s/ William R. Broaddrick
Chief Financial Officer

HANSEN, BARNETT & MAXWELL, P.C.
A Professional Corporation CERTIFIED PUBLIC ACCOUNTANTS AND BUSINESS CONSULTANTS 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 management’s assessment, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting, that Arena Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). 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 management’s assessment and an opinion on the effectiveness of 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 included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and 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, management’s assessment that Arena Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2006 is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Arena Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the COSO criteria.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Arena Resources, Inc. as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2006 of Arena Resources, Inc. and our report dated March 29, 2007 expressed an unqualified opinion thereon.

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

Salt Lake City, Utah
March 29, 2007

Changes in Internal Control Over Financial Reporting

We made no change in our internal control over financial reporting during our fourth quarter of 2006 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, 2006:

Name	Age	Position
Lloyd T. Rochford	60	President and Chief Executive Officer and Director
Stanley M. McCabe	74	Chairman of the Board of Directors, Secretary and Treasurer
William R. Broaddrick	29	Vice President and Chief Financial Officer
Charles M. Crawford	54	Director
Chris V. Kemendo, Jr.	85	Director
Clayton E. Woodrum	66	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 2006.

Messrs. Rochford, McCabe and Crawford have served as directors since our inception in August 2000. Mr. Kemendo was first elected to the Board of Directors in February 2003 and Mr. Woodrum was initially appointed in August 2003 by the Board of Directors to fill a vacancy created upon the resignation of a director.

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

Lloyd T. Rochford – President, Chief Executive Officer and Director.

Mr. Rochford, 60, 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.

Stanley M. McCabe – Chairman of the Board of Directors, Secretary and Treasurer.

Mr. McCabe, 74, 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.

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

Mr. Broaddrick, 29, 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.

Charles M. Crawford – Director

Mr. Crawford, 54, has for the past twenty-nine years served as an independent oil and gas exploration consultant to various private and public oil and gas companies within the United States. He has acted as a consultant to such firms as Texaco, Inc, Phillips Petroleum Company, Mid-Continent Energy Corp. as well as other regional and national companies primarily acting in the mid-continent area. Mr. Crawford received a Masters Degree in geology from Miami University of Ohio, in 1976. Mr. Crawford will serve the company on an as needed basis as an outside director.

Chris V. Kemendo, Jr. – Director.

Mr. Kemendo, passed away on January 5, 2007. From 1989 until his death, Mr. Kemendo acted as an independent financial business and accounting consultant to various clients. Mr. Kemendo had 57 years of accounting experience. Mr. Kemendo graduated from the University of Oklahoma and subsequently became a Certified Public Accountant. From 1947 to 1957, Mr. Kemendo was a manager of Arthur Young & Company, in charge of audit departments in Kansas City, Missouri, Wichita, Kansas and Caracas, Venezuela. From 1957 to 1961, Mr. Kemendo served as Controller and CFO for Rio Arriba Drilling Company. From 1961 to 1967, he was a partner of Fox & Company, Certified Public Accountants. From 1967 to 1973, he served as Executive Vice-President and CFO of LaBarge, Inc. From 1973 to 1979, Mr. Kemendo was a partner at Daniel and Howard, Inc. From 1979 to 1982, he again served as a partner at Fox & Company (now Grant Thornton, LLP). From 1982 to 1988, Mr. Kemendo was Executive Vice-President and Director at Fitzgerald, DeArman & Roberts, Inc.

Clayton E. Woodrum – Director.

Mr. Woodrum, 66, is a Certified Public Accountant and has, from 1984 to present, been a principal shareholder in the accounting firm of Woodrum, Kemendo, Tate & Cuite, 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. One of Mr. Woodrum’s partners at Woodrum, Kemendo, Tate & Cuite, P.L.L.C., Ben Kemendo, is the son of Chris Kemendo, Jr.

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 2007 annual meeting of stockholders, and in each case until their respective successors are duly elected and qualified.

None of our directors currently serves as a director of any other company which is required to file periodic reports under the Securities Exchange Act of 1934.

New Board and Officer Appointments Subsequent to December 31, 2006.

On January 5, 2007, Chris V. Kemendo, Jr., passed away after a brief illness. As discussed in more detail below, as an “independent director” of the Company, Mr. Kemendo had served as a member of our Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee.

Pursuant to the authority granted to the Board of Directors by the Company’s Bylaws, effective January 9, 2007, the remaining directors unanimously appointed Mr. Anthony B. Petrelli to fill the vacancy in the Board of Directors created by Mr. Kemendo’s death. Mr. Petrelli is currently Senior Vice President of Neidiger Tucker Bruner, Inc., which firm served as one of the lead underwriters in the Company’s secondary registration of its common stock in August of 2004.

On February 1, the Board of Directors announced that Phillip Terry has been appointed to the newly created office of “President and Chief Operating Officer”. Tim Rochford has retained the position of “Chief Executive Officer” of the Company. Also, the Board of Directors appointed William Parsons to the newly created position of “Vice President and Manager of Investor Relations”.

Mr. Terry, 59, 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 34 years experience in engineering, production, drilling, completions, reservoir engineering, property evaluations and corporate management in the oil and gas industry.

As President and Chief Operating Officer, Mr. Terry is responsible for the day-to-day management of the operational business and affairs of the Company. Mr. Terry reports directly to Mr. Rochford who, as Chief Executive Officer, will continue to be responsible for the overall supervision of the policy, direction and control of the Company.

Mr. Parsons, 58, has since 1992 served as President of K M Financial, Inc., a Scottsdale, Arizona based consulting, marketing and investment relations firm which specializes in providing these services to companies whose stock has recently become publicly-traded. The Company has been a client of K M Financial, Inc. since the Company’s formation, and for this reason, Mr. Parsons is intimately familiar with all aspects of the Company’s operations, and also has extensive experience in investor and market communications associated with the securities markets.

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 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 2006, the Audit Committee was comprised of our three independent directors, Messrs. Kemendo, Woodrum and Crawford, with Mr. Woodrum acting as the chairman. Our Board of Directors determined that both Messrs. Kemendo and Woodrum qualified as “audit committee financial expert” under the rules of the SEC adopted pursuant to requirements of the Sarbanes-Oxley Act of 2002 (see the biographical information for each of Messrs. Kemendo and Woodrum, infra, in this discussion of “Directors and Executive Officers.)” Each of Messrs. Kemendo, Woodrum and Crawford 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. Upon the death of Mr. Kemendo in January 2007, the board appointed Mr. Petrelli to fill the position left vacant on the Audit Committee. The Board of Directors has determined that Mr. Petrelli qualifies 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.

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 (on which our shares are listed), 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 2006, the Compensation Committee was comprised of our three independent directors, Messrs. Kemendo, Woodrum and Crawford, with Mr. Woodrum acting as the chairman. Upon the death of Mr. Kemendo in January 2007, the Board appointed Mr. Petrelli to fill the position left vacant on the Compensation Committee.

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 2006, the committee was comprised of Messrs. Kemendo, Woodrum and Crawford, our three independent directors, with Mr. Woodrum acting as Chairman. Upon the death of Mr. Kemendo in January 2007, the Board appointed Mr. Petrelli to fill the position left vacant on the Nominating and Corporate Governance Committee.

There has 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 that applies to our principal executive officer, principal financial officer and principal accounting officer or persons performing similar functions (as well as its other employees and directors). The Company undertakes to provide any person without charge, upon request, a copy of such code of ethics. Requests may be directed to Arena Resources, Inc., 4920 S. Lewis Ave., Suite 107, Tulsa, Oklahoma 74105, 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.

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	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 salaries and bonuses of Messrs. McCabe and Rochford have, at their insistence, been historically lower than salaries and bonuses of comparable executives of peer companies. With respect to other executive officers of the Company, 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. With the exception of the base salaries paid to Messrs. McCabe and Rochford noted above, a significant portion of the executive compensation package is through base salaries. Effective August 1, 2006, the Compensation Committee increased salaries for Named Officers by an aggregate of $39,000 resulting in the following individual base salaries for the Named Officers: Stanley McCabe — $36,000, Lloyd T. Rochford — $36,000, William R. Broaddrick — $75,000, Phillip Terry — $120,000 and H. D. Haston — $70,000. 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 December of 2006 for two 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

It is our policy is 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 for 2006 was awarded in the form of the Company’s non-qualified stock options. Stock option grants are valued using the Black-Scholes Model in accordance with SFAS 123 (R) 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 5 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 SFAS 123 (R). 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 aggregate amount as determined under SFAS 123(R) recognized for purposes of our financial statements for 2006 with respect to outstanding options granted to the Named Officers is shown in the “Summary Compensation Table” below. The grant date fair value of the option awarded to the Named Officers in 2006 as determined under SFAS 123 (R) for purposes of our financial statements is shown in the “Grants of Plan-Based Awards” table below. The “Grants of Plan-Based Awards” table below provides additional detail regarding the options granted to Named Officers in 2006, including the vesting and other terms that apply to the options.

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 2006 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)
Charles M. Crawford

_________________

(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 all of 2006. The other member of the Compensation Committee during 2006, Mr. Chris V. Kemendo, Jr. passed away on January 5, 2007, and was, therefore, unable to participate in the preparation of the Compensation Committee’s Report on Executive Compensation. 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 “Grants of Plan-Based Awards” table, and the description of the material terms of the nonqualified options granted in 2006 that follows it, provides information regarding the long-term equity incentives awarded to Named Officers in 2006 that are also reported in the “Summary Compensation Table”. 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, 2006.

Summary Compensation Table


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

Lloyd T. Rochford, President and Chief Executive Officer	2006		36,000		-		-		-		36,000

Stanley McCabe, Chairman of the Board	2006		36,000		-		-		-		36,000

William R. Broaddrick, Vice President and Chief Financial Officer	2006		65,666		-		-		-		65,666

Phillip W. Terry, Manager of Operations	2006		106,583		12,000		-		12,000		130,583

H. D. Haston, General Manager, Arena Drilling Company	2006		86,500		10,000		876,618		20,400		993,518

(1) See discussion of assumptions made in valuing these awards in the notes to the company’s financial statements.
(2) All Other Compensation was cash paid as vehicle allowances.

The Company awards stock incentives to key employees and the Named Officers either on the initial date of employment or due to performance incentives throughout the year. The 2006 grants to Named Officers are reported in the table below.

Grants of Plan-Based Awards

Name	Grant Date	All Other Option Awards: Number of Securities Underlying Options (#)	Exercise or Base Price of Option Awards ($)	Fair Value on Grant Date (1)

H. D. Haston	06/14/06	50,000	27.40	876,618

(1) See discussion of assumptions made in valuing these awards in the notes to the company’s financial statements

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.

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

Lloyd T. Rochford	75,000	50,000	3.70	10/01/08
	25,000	100,000	8.30	07/01/10

Stanley McCabe	75,000	50,000	3.70	10/01/08
	25,000	100,000	8.30	07/01/10

William R. Broaddrick	100,000	100,000	3.70	10/01/08

Phillip W. Terry	100,000	100,000	3.70	10/01/08

H. D. Haston	-	50,000	27.40	12/14/11

The following table presents information regarding the exercise of stock options by Named Officers during 2006.

Option Exercises and Stock Vesting


	Option Awards
Name	Number of Share Acquired on Exercise (#)	Value Realized on Exercise ($)
William R. Broaddrick	50,000	1,273,000
Phillip W. Terry	50,000	1,609,500
Raymond H. Estep	40,000	1,280,000
Clayton E. Woodrum	10,000	292,500
Charles M. Crawford	10,000	304,800
Chris V. Kemendo, Jr.	10,000	304,800

Director Compensation

All outside directors are currently compensated with a stipend of $500 per month plus $500 for each meeting of the directors attended. No director receives a salary as a director.

The Company made a grant of options in 2003 to its directors, at which time Messrs. Kemendo, Woodrum and Crawford received 50,000 non-qualified stock options each that vest ratably over five years. The Company made a grant of options in 2005 to its directors at which time Messrs. Woodrum and Crawford received an additional 12,500 options and Mr. Kemendo received an additional 25,000 options.

Director Compensation Table


Name	Fees Earned or Paid in Cash ($)	Option Awards ($)	All Other Compensation ($)		Total ($)

Clayton E. Woodrum	7,500	-	-	(1)	7,500
Charles M. Crawford	7,500	-	-	(2)	7,500
Chris V. Kemendo, Jr.	7,500	-	-	(3)	7,500

(1) There were 52,500 options outstanding to this Director at December 31, 2006.
(2) There were 52,500 options outstanding to this Director at December 31, 2006.
(3) There were 65,000 options outstanding to this Director at December 31, 2006.

The following table sets forth information concerning our executive stock option plan as of December 31, 2006.

	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	1,305,000	6.65	1,025,000

Equity compensation plans not approved by security holders	-	-	-

Total	1,305,000	6.65	1,025,000

Item 12:

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth, as March 27, 2007, information regarding the beneficial ownership of our common stock: (i) by each of our directors and executive officers; (ii) by all directors and executive officers as a group; and (iii) by all persons known to us to own 5% or more of our outstanding shares of common stock. 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	997,700 ⁽¹⁾	7%
Stanley M. McCabe	798,000 ⁽²⁾	5%
William R. Broaddrick	104,500 ⁽³⁾	1%
Charles M. Crawford	25,000 ⁽⁴⁾	*
Chris V. Kemendo, Jr.	40,100 ⁽⁵⁾	*
Clayton E. Woodrum	35,000 ⁽⁶⁾	*

All directors and executive officers	2,000,300 ⁽⁷⁾	13%

(1)

Includes 125,000 shares issuable upon the exercise of stock options that are currently exercisable and 25,000 shares issuable upon the exercise of stock options that are exercisable within 60 days.

(2)

Includes 125,000 shares issuable upon the exercise of stock options that are currently exercisable and 25,000 shares issuable upon the exercise of stock options that are exercisable within 60 days.

(3)

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

(4)

Includes 15,000 shares issuable upon the exercise of stock options that are currently exercisable and 10,000 shares issuable upon the exercise of stock options that are exercisable within 60 days.

(5)

Includes 25,000 shares issuable upon the exercise of stock options that are currently exercisable and 15,000 shares issuable upon the exercise of stock options that are exercisable within 60 days.

(6)

Includes 25,000 shares issuable upon the exercise of stock options that are currently exercisable and 10,000 shares issuable upon exercise of stock options that are exercisable within 60 days.

(7)

Includes 365,000 shares issuable upon the exercise of stock options that are currently exercisable and 135,,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%

Percentage ownership calculations for any stockholder listed above are based on 14,821,263 shares of our common stock outstanding as of March 27, 2007.

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 mature on January 1, 2008. The notes bear interest at a rate of 10% per annum, and are secured by our assets (although such notes are 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 in 2006 Messrs. Kemendo, Crawford and Woodrum were 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, 2006, and the Audit Committee has selected HBM to serve in the same capacity for the fiscal year ending December 31, 2007. 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 $95,870 and $75,000 for professional services rendered for the audit of the Company’s financial statements for the years ended December 31, 2006 and 2005, respectively, and its reviews of the Company’s financial statements included in its Form 10-Q’s for the first three quarters of 2006 and, 2005.

Audit Related Fees. HBM billed the Company $17,320 and $5,000 for the years ended December 31, 2006 and 2005, respectively, for its services in connection with the review of the Company’s registration statement on Form S-3, which was originally filed with the SEC in 2005 and was amended in 2006.

Tax Fees. HBM billed the Company an aggregate of $5,000 and $5,000 for professional services rendered for tax compliance, tax advice and tax planning for the years ended December 31, 2006 and 2005.

All Other Fees. No other fees were billed by HBM to the Company during 2006 and 2005.

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 50

(b)

Exhibits

3.1

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

3.2

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

10.1

Business Loan Agreement, dated as of April 14, 2004, among Arena Resources, Inc. and MidFirst Bank, N.A. (ii)

10.2

Business Loan Agreement, dated as of May 7, 2004, among Arena Resources, Inc. and MidFirst Bank, N.A. (ii)

10.3

Business Loan Agreement, dated as of November 16, 2004, among Arena Resources, Inc. and MidFirst Bank, N.A. (iii)

10.4

East Hobbs Purchase and Sales Agreement Dated April 22, 2004 (ii)

10.5

Fuhrman-Mascho Purchase and Sales Agreements Dated December 1, 2004 (iii)

Subsidiaries of the Registrant

23.1

Consent of Lee Keeling and Associates, 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

(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 exhibits to Arena Resources, Inc.‘s From 8-K filed May 18, 2004.

(iii) Incorporated herein by reference to the exhibits to Arena Resources’ Form 10-KSB filed March 17, 2005.

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:	/s/ Lloyd T. Rochford
		Mr. Lloyd T. Rochford,
		Chief Executive Officer

	Date: March 30, 2007

	By:	/s/ Stanley McCabe
		Mr. Stanley McCabe
		Treasurer, Secretary

	Date: March 30, 2007

	By:	/s/ William R. Broaddrick
		Mr. William R. Broaddrick
		Chief Financial Officer

	Date: March 30, 2007

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.

	/s/ Lloyd T. Rochford
	Mr. Lloyd T. Rochford
	Director

	Date: March 30, 2007

	/s/ Stanley McCabe
	Mr. Stanley McCabe
	Director

	Date: March 30, 2007

	/s/ Charles Crawford
	Mr. Charles Crawford
	Director

	Date: March 30, 2007

	/s/ Clayton E. Woodrum
	Mr. Clayton E. Woodrum
	Director

	Date: March 30, 2007

	/s/ Anthony B. Petrelli
	Mr. Anthony B. Petrelli
	Director

	Date: March 30, 2007

ARENA RESOURCES, INC.

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	56
Balance Sheets	57
Statements of Operations	58
Statements of Stockholders' Equity	59
Statements of Cash Flows	60
Notes to Financial Statements	62
Supplemental Information on Oil and Gas Producing Activities	76

HANSEN, BARNETT & MAXWELL, P.C.
A Professional Corporation CERTIFIED PUBLIC ACCOUNTANTS AND BUSINESS CONSULTANTS 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, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006. 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, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 123R, Share-Based Payment, effective January 1, 2006.

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, 2006, 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 29, 2007 expressed an unqualified opinion thereon.

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

Salt Lake City, Utah
March 29, 2007

ARENA RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS

December 31,	December 31, 2006			December 31, 2005

ASSETS
Current Assets
Cash	$	4,919,984	$	4,317,114
Accounts receivable		6,702,677		3,180,749
Joint interest billing receivable		2,949,099		140,561
Prepaid expenses		102,585		35,436

Total Current Assets		14,674,345		7,673,860

Property and Equipment
Oil and gas properties subject to amortization, Using Full Cost Accounting		171,708,200		69,770,685
Equipment		59,332		26,687
Drilling rig		1,996,899		1,191,126
Office equipment		120,929		106,177

Total Property and Equipment		173,885,360		71,094,675
Less: Accumulated depreciation and amortization		(12,246,727)		(4,346,628)

Net Property and Equipment		161,638,633		66,748,047

Total Assets	$	176,312,978	$	74,421,907


LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	14,367,252	$	6,038,691
Income taxes payable		-		329,986
Accrued liabilities		628,618		221,519

Total Current Liabilities		14,995,870		6,590,196

Long-Term Liabilities
Notes payable		19,300,000		-
Notes payable to related parties		400,000		400,000
Asset retirement liability		2,250,332		1,515,347
Deferred income taxes		19,322,724		7,187,609

Total Long-Term Liabilities		41,273,056		9,102,956

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; 14,668,787 shares and 13,099,702 shares outstanding, respectively		14,669		13,100
Additional paid-in capital		81,872,268		45,331,234
Options and warrants outstanding		2,872,988		1,483,807
Deferred compensation		-		(115,545)
Retained earnings		35,284,127		12,016,159

Total Stockholders' Equity		120,044,052		58,728,755

Total Liabilities and Stockholders' Equity	$	176,312,978	$	74,421,907

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

ARENA RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS

*For the years ended December 31,*		2006		2005		2004

Oil and Gas Revenues	$	59,760,117	$	25,843,077	$	8,482,130

Costs and Operating Expenses
Oil and gas production costs		6,453,831		3,832,486		1,975,835
Oil and gas production taxes		3,506,347		1,939,739		629,703
Depreciation, depletion and amortization		7,900,099		2,781,504		1,011,602
Accretion expense		127,132		102,585		53,729
General and administrative expense		3,617,309		1,365,590		874,850

Total Costs and Operating Expenses		21,604,718		10,021,904		4,545,719

Other Income (Expense)
Gain from change in fair value of put options		-		95,033		68,251
Other financing expense		(785,598)		(597,773)		-
Interest (expense)		(124,833)		(229,624)		(155,936)

Net Other Income (Expense)		(910,431)		(732,364)		(87,685)

Income Before Provision for Income Taxes		37,244,968		15,088,809		3,848,726

Provision for Income Taxes		(13,977,000)		(5,628,126)		(1,397,074)

Net Income	$	23,267,968	$	9,460,683	$	2,451,652


Basic Net Income Per Common Share	$	1.65	$	0.85	$	0.31
Diluted Net Income Per Common Share		1.55		0.75		0.28

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

ARENA RESOURCES, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2004, 2005 AND 2006

	Common Stock
					Additional		Options and						Total
	Shares		Amount		Paid-in Capital		Warrants Outstanding		Deferred Compensation		Retained Earnings		Stockholders' Equity

Balance December 31, 2003	7,162,097	$	7,162	$	6,994,925	$	1,473,164	$	(438,802)	$	103,824	$	8,140,273
Warrants exercised	78,300		78		395,843		(41,796)		-		-		354,125
Issuance for cash, net	1,667,500		1,668		6,469,225		1,781,791		-		-		8,252,684
Issuance of common stock in property acquisitions, net of call option received	225,013		225		1,398,359		-		-		-		1,398,584
Amortization of deferred compensation	-		-		-		-		204,525		-		204,525
Net income	-		-		-		-		-		2,451,652		2,451,652

Balance December 31, 2004	9,132,910		9,133		15,258,352		3,213,159		(234,277)		2,555,476		20,801,843
Warrants exercised for cash, net	2,971,273		2,971		20,194,042		(2,322,392)		-		-		17,874,621
Expiration of warrants	-		-		4,733		(4,733)		-		-		-
Issuance of common stock in
property acquisition	25,000		25		340,625		-		-		-		340,650
Issuance for cash, net	970,874		971		9,535,967		-		-		-		9,536,938
Issuance of warrants for services relating to private offering	-		-		-		597,773		-		-		597,773
Cancellation of stock issued in property acquisition	(355)		-		(2,485)		-		-		-		(2,485)
Amortization of deferred compensation	-		-		-		-		118,732		-		118,732
Net income	-		-		-		-		-		9,460,683		9,460,683

Balance December 31, 2005	13,099,702		13,100		45,331,234		1,483,807		(115,545)		12,016,159		58,728,755
Issuance of common stock in property acquisition	131,000		131		3,752,755		-		-		-		3,752,886
Issuance of common stock as part of drilling rig acquisition	6,200		6		181,034		-		-		-		181,040
Warrants exercised for cash, net	50,000		50		165,850		(15,900)		-		-		150,000
Warrants exercised using cashless exercise provision	61,885		62		49,621		(49,683)		-		-		-
Option exercised for cash	170,000		170		752,230		(112,400)		-		-		640,000
Issuance for cash, net	1,150,000		1,150		29,787,729		-		-		-		29,788,879
Tax impact of option exercises	-		-		1,851,815		-		-		-		1,851,815
Issuance of warrants for services - relating to private offering	-		-		-		785,598		-		-		785,598
Expense related to vesting stock based compensation	-		-		-		897,111		-		-		897,111
Elimination of deferred compensation	-		-		-		(115,545)		115,545		-		-
Net income	-		-		-		-		-		23,267,968		23,267,968

Balance December 31, 2006	14,668,787	$	14,669	$	81,872,268	$	2,872,988	$	-	$	35,284,127	$	120,044,052

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

ARENA RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

*For the years ended December 31,*		2006		2005		2004

Cash Flows From Operating Activities
Net income	$	23,267,968	$	9,460,683	$	2,451,652
Adjustments to reconcile net income to net cash provided by operating activities:
Warrants issued for financing expense		785,598		597,773		-
Depreciation, depletion and amortization		7,900,099		2,781,504		1,011,602
Provision for income taxes		13,977,000		5,628,126		1,397,074
Gain from change in fair value of put option		-		(95,033)		(68,251)
Loss on sale of equipment		-		-		5,586
Share based compensation		897,111		118,732		204,525
Accretion of asset retirement obligation		127,132		102,585		83,730
Changes in assets and liabilities:
Accounts and joint interest receivable		(6,330,466)		(2,109,992)		(656,864)
Other changes in deferred income taxes		(320,058)		(82,521)		-
Prepaid expenses		(67,149)		(2,300)		(4,201)
Excess tax benefits from share-based payment arrangements		(1,851,815)		-		-
Accounts payable and accrued liabilities		8,729,479		4,419,545		1,570,831

Net Cash Provided by Operating Activities		47,114,899		20,819,102		5,995,684

Cash Flows from Investing Activities
Proceeds from sale of property and equipment		-		735,000		10,500
Cash payments on purchase of East Hobbs		-		-		(1,028,000)
Cash payments on purchase of Fuhrman Mascho properties		-		-		(711,802)
Purchase and development of oil and gas properties		(97,576,774)		(34,665,614)		(4,802,141)
Maturity of long term investment		-		-		25,234
Purchase of machinery and office equipment		(672,130)		(1,236,902)		(41,423)

Net Cash Used in Investing Activities		(98,248,904)		(35,167,516)		(6,547,632)

Cash Flows From Financing Activities
Proceeds from issuance of common stock and warrants, net of offering costs		29,788,879		9,536,938		8,383,557
Proceeds from exercise of warrants, net of offering costs		150,000		17,874,621		354,124
Proceeds from exercise of options		640,000		-		-
Excess tax benefits from share-based payment arrangements		1,851,815		-		-
Funds received and held for call options		1,272,093		-		-
Funds paid from funds held for call options		(1,265,912)		-		-
Issuance of notes payable		30,300,000		-		2,000,000
Payment of notes payable		(11,000,000)		(10,000,000)		(10,008,440)

Net Cash Provided by Financing Activities		51,736,875		17,411,559		729,241

Net Increase in Cash		602,870		3,063,145		177,293

Cash at Beginning of Period		4,317,114		1,253,969		1,076,676

Cash at End of Period	$	4,919,984	$	4,317,114	$	1,253,969

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

ARENA RESOURCES, INC.
STATEMENTS OF CASH FLOWS (CONTINUED)

*For the years ended December 31,*		2006		2005		2004

Supplemental Cash Flow Information
Cash paid for income taxes	$	329,986	$	82,521	$	-
Cash paid for interest	$	240,815	$	199,624	$	158,950

Non-Cash Investing and Financing Activities
Common stock issued for properties	$	3,933,926	$	340,650	$	34,500
Asset retirement obligation incurred in property acquisition and development		607,853		144,769		570,029
East Hobbs property was acquired as follows:
Fair value of assets acquired	$	-	$	-	$	10,354,964
Liabilities assumed		-		-		(78,654)
Notes payable incurred		-		-		(9,008,440)
Common stock issued		-		-		(239,870)

Cash paid	$	-	$	-	$	1,028,000

Fuhrman-Mascho property was acquired as follows:
Fair value of assets acquired	$	-	$	-	$	11,479,742
Liabilities assumed		-		-		(513,247)
Note payable incurred, net of $30,000 unamortized discount		-		-		(8,970,000)
Put options issued		-		-		(160,379)
Common stock issued		-		-		(1,260,091)
Call options received		-		-		135,777

Cash paid	$	-	$	-	$	711,802

The accompanying notes are an integral part of these 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. Arena Drilling Co. was formed to oversee the operation of the Company’s drilling rig that began operating in May 2006. ARD Production was formed to hold LZS Corporation, an acquisition the Company made in November 2006. 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.

Fair Values of Financial Instruments — The carrying amounts reported in the balance sheets for accounts receivable, accounts payable, and accrued liabilities approximate fair value because of the immediate or short-term maturity of these financial instruments. The carrying amounts reported for notes payable and long-term debt approximate fair value because the underlying instruments are at interest rates which approximate current market rates.

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 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. 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, 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 or until impairment occurs. 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 our total depletion and amortization and depletion per barrel-of-oil-equivalent rate, by year for the years ended December 31, 2006, 2005 and 2004.

	For the Years Ended December 31,
		2006		2005		2004

Depletion	$	7,741,110	$	2,757,187	$	997,694
Depletion rate, per barrel-of-oil-equivalent (BOE)	$	7.30	$	5.42	$	4.47

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 computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions;
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.

Support and Office Equipment – Depreciation of support and office equipment is computed using the straight-line method over the estimated useful lives of the assets which are currently five to seven years. Depreciation expense was $25,864, $22,659 and $13,908 for the years ended December 31, 2006, 2005 and 2004, respectively. Additionally, with the completed acquisition of our drilling rig in 2006, we had depreciation on the rig of $133,125 in 2006.

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. 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.

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.

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Major Customers – During the year ended December 31, 2006, sales to one customer represented 82% of total sales, respectively. At December 31, 2006, this customer made up 80% of accounts receivable. During the year ended December 31, 2005, sales to two customers represented 72% and 12% of total sales, respectively. At December 31, 2005, these two customers made up 77% and 8% of accounts receivable, respectively. During the year ended December 31, 2004, sales to two customers represented 43% and 31% of total sales, respectively. At December 31, 2004, these two customers made up 43% and 22% 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 to directors and employees, which are described more fully in Note 8. Effective January 1, 2006, the Company adopted Statements of Financial Standards 123R, Share-Based Payment (SFAS 123R), using the modified prospective method. SFAS 123R requires 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. SFAS 123R 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). Prior to our adopting SFAS 123R, the Company accounted for stock-based compensation plans under Accounting Principles Board Opinion (“APB”) No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). Under APB 25, no compensation expense is recorded when the terms of the award are fixed and the exercise price of the employee stock option equals or exceeds the fair value of the underlying stock on the date of grant. The Company's net income decreased by $552,323, or $0.04 per share, in 2006 due to the adoption of SFAS 123R.

Stock-based employee compensation incurred for the years ended December 31, 2006, 2005 and 2004 was $897,111, $118,732 and $204,525, respectively.

Prior to January 1, 2006, the Company determined the value of stock-based compensation arrangements under the provisions of APB Opinion No. 25 “Accounting for Stock Issued to Employees” and made pro forma disclosures required under SFAS No. 123, “Accounting for Stock-Based Compensation.” Had compensation expense for stock option grants been determined based on the fair value at the grant dates consistent with the method prescribed in SFAS No. 123, the Company’s net income and net income per share would have been adjusted to the pro forma amounts below for the years ended December 31, 2005 and 2004:

*For the Years Ended December 31,*		2005		2004

Net income, as reported	$	9,460,683	$	2,451,652
Add: Stock based employee compensation expense included
in net income, net of related tax effects		74,444		128,365
Deduct: Total stock-based employee compensation expense
determined under the fair value based method for all awards, net of related tax effects		(555,051)		(345,068)

Pro Forma Net Income	$	8,980,076	$	2,234,949

Income Per Common Share
Basic, as reported	$	0.85	$	0.31
Basic, pro forma		0.80		0.28

Diluted, as reported	$	0.75	$	0.28
Diluted, pro forma		0.71		0.26

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 SFAS No. 123, “Accounting for Stock-Based Compensation.” Under SFAS No. 123, 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.

Recent Accounting Pronouncements – In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” an interpretation of FASB Statement No. 109 (FIN 48). FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006, and the Company is still evaluating the effects of adopting this standard, but does not expect it to have a material effect on the Company’s consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). This statement establishes a framework for fair value measurements in financial statements by providing a single definition of fair value. This standard provides guidance on the methods used to estimate fair value and increases disclosures about estimate of fair value. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and is generally applied prospectively. The Company is currently evaluating the impact of this statement on its consolidated financial statements.

In September 2006, the Securities Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB No. 108”). SAB No. 108 addresses how the effects of prior year uncorrected misstatements should be considered when quantifying misstatements in current year financial statements. SAB No. 108 requires companies to quantify misstatements using a balance sheet and income statement approach and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. When the effect of initial adoption is material, companies will record the effect as a cumulative effect adjustment to beginning of year retained earnings and disclose the nature and amount of each individual error being corrected in the cumulative adjustment. SAB No. 108 will be effective beginning January 1, 2007 and it is anticipated that the initial adoption of SAB No. 108 will not have a material impact on the Company’s financial statements.

NOTE 2 – EARNINGS PER SHARE INFORMATION

For the Years Ended December 31,		2006		2005		2004

Net Income	$	23,267,968	$	9,460,683	$	2,451,652

Basic Weighted-Average Common Shares Outstanding		14,066,540		11,164,070		7,873,213
Effect of dilutive securities
Warrants		244,261		838,773		524,173
Stock options		713,953		597,263		296,792

Diluted Weighted-Average Common Shares Outstanding		15,024,754		12,600,106		8,694,178

Basic Income Per Common Share
Net income		1.65		0.85		0.31

Diluted Income Per Common Share
Net Income		1.55		0.75		0.28

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3 – ACQUISITION OF OIL AND GAS PROPERTIES

East Hobbs – On May 7, 2004, the Company acquired an 82.24% working interest, 67.60% net revenue interest, in the East Hobbs San Andres Property mineral lease (“East Hobbs”) located in Lea County, New Mexico. Although the Purchase and Sales Agreement transferred the revenue and the related operating costs from East Hobbs to Arena beginning March 1, 2004, Arena did not control the property interests until May 7, 2004. As a result, the acquisition date for accounting purposes was May 7, 2004 and the East Hobbs’ operations have been included in the results of operations of Arena from May 7, 2004. Revenues and operating costs for the months of March and April were treated as adjustments to the purchase price.

At the date of acquisition, East Hobbs was comprised of 21 operating oil and gas wells that were unitized into one lease prior to the acquisition. The Company purchased East Hobbs for its current production and cash flow, as well as for the drilling and secondary recovery opportunities from the property. The Company paid $10,008,440 to the sellers, including $9,008,440 paid directly from borrowings under a credit facility and a bridge financing from a bank described more fully in Note 5. In addition, the Company paid acquisition costs of $28,000 and issued 40,000 shares of common stock valued at $239,750, or $5.99 per share.

Furhman-Mascho – On November 18, 2004, Arena Resources, Inc. entered into a binding letter of intent to acquire 100% of the working interest, 75% of the net revenue interest, of the Fuhrman-Mascho Property mineral leases under the terms of Asset Purchase Agreements (the “Agreements”). Under the terms of the Agreements, the sellers transferred effective control of the property to the Company on December 1, 2004 without restrictions. Accordingly, the acquisition date was December 1, 2004. The results of operations of the Fuhrman-Mascho property have been included in the results of operations of the Company from December 1, 2004.

At the date of acquisition, the Fuhrman-Mascho property consisted of 84 leases with a total of 174 operating oil and gas wells. The Company purchased Fuhrman-Mascho for its current production and cash flow, as well as for the drilling and development opportunities from the property. On December 20, 2004, the Company made cash payments to the sellers of $9,667,381, issued the sellers 149,658 shares of common stock valued at $1,050,091 or $7.00 per share based on the market value of the common stock over the 2-day period before and after November 18, 2004, issued the sellers put options entitling the sellers to demand that the Company reacquire the 149,658 shares of common stock at $7.00 per share from November 1, 2006 through November 30, 2006, valued at $160,379 using the Black-Scholes option pricing model, and received call options from the sellers entitling the Company to reacquire the 149,658 shares of common stock at $8.50 per share from the date issued through November 1, 2006 and valued at $135,777 using the Black-Scholes option pricing model. In addition, the Company paid acquisition costs of $44,421 and issued 30,000 shares of common stock as a consulting and finder’s fee, valued at $210,000, or $7.00 per share. The consideration paid or issued on December 20, 2004 was discounted to December 1, 2004 at 5% and resulted in recognition of an unamortized discount of $30,000 at December 1, 2004. The acquisition was funded through the use of cash on hand and a credit facility secured from the Company’s principal lender.

The following unaudited pro forma information is presented to reflect the operations of the Company as if the acquisitions of the East Hobbs and the Fuhrman-Mascho properties had been completed on January 1, 2004:

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the Year Ended December 31,		2004

	(Unaudited)
Oil and Gas Revenues	$	11,493,181
Income from Operations Before Cumulative Effect of Change in
Accounting Principle		2,833,800
Net Income		2,833,800

Basic Income Per Common Share
Income before cumulative effect of change in accounting principle	$	0.36
Net income		0.36
Basic Income Per Common Share
Income before cumulative effect of change in accounting principle	$	0.33
Net income		0.33

The full year of operations from both of these properties was included in our operating statement for the years ended December, 31, 2006 and 2005.

Other Acquisitions – During 2005, the Company acquired working interests in leases near its Fuhrman Mascho properties acquired in 2004. The working interests acquired ranged from 20.2% to 100%, and the net revenue interest ranged from 16.1% to 79.2%. Total acquisition costs, included 5,000 shares of restricted common stock valued at $15.81 per share, or $79,050, and cash of $1,327,538. The pro forma impact of this acquisition was not material to the Company’s historical results of operations.

During 2005, the Company acquired the lease rights to a total of 19,840 acres in Hamilton and Greeley Counties, Kansas. Total acquisition cost was $574,546, which included 20,000 shares of restricted common stock valued at $13.08 per share, or $261,600, and cash of $312,946. Subsequent to the acquisition of these leases, the Company sold a partial working interest in four wells the Company drilled and a right of first refusal on wells drilled offsetting those wells. Total funds received for these working interests were $735,000. These funds received were accounted for as an offset to capitalized costs. In February 2006, the Company issued 120,800 shares of the Company’s stock, valued at $3,326,832, or $27.54 per share, to re-acquire the interests sold.

During 2006, the Company acquired working interests in leases near its Fuhrman Mascho properties acquired in 2004. The working interests acquired ranged from 72.5% to 100%, and the net revenue interests ranged from 55% to 80%. As a part of these acquisitions, the Company acquired the entire LZS Corporation. Total acquisition costs of $6,293,368, included 10,200 shares of restricted common stock valued at $41.77 per share, or $426,054 and cash of $5,867,314.

During 2006, the Company acquired 15,573 acres of lease rights at a total cost of $543,350 in various locations.

NOTE 4 – 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:

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Capitalized Costs Relating to Oil and Gas Producing Activities

December 31,		2006		2005		2004

Unproved oil and gas properties	$	5,099,974	$	692,783	$	388,581
Proved oil and gas properties		166,608,226		69,077,903		34,068,557
Drilling advances on uncompleted projects		-		-		900,000
Acquisition of drilling rig		1,996,899		1,191,126		-
Support and office equipment		180,261		132,863		87,087

Total capitalized costs		173,885,360		71,094,675		35,444,225
Less accumulated depletion, depreciation and amortization		(12,246,727)		(4,346,628)		(1,565,124)

Net Capitalized Costs	$	161,638,633	$	66,748,047	$	33,879,101

Costs Incurred in Oil and Gas Producing Activities

For the Years Ended December 31,		2006		2005		2004

Acquisition of proved properties		7,122,176		1,406,588		21,706,166
Acquisition of unproved properties (net of proceeds from property sale)		3,282,635		(160,454)		43,082
Exploration costs		1,124,556		464,656		216,805
Development costs		89,797,285		32,557,989		4,027,754

Total Costs Incurred	$	101,326,652	$	34,268,779	$	25,993,807

NOTE 5 – NOTES PAYABLE AND PUT OPTION

Notes Payable – On April 14, 2004, the Company established a credit facility with its principal lenders. In April 2005, the Company entered into an agreement that increased its credit facility to $50,000,000, with an increased borrowing base of $35,000,000. The interest rate was a floating rate equal to the 30, 60 or 90 day LIBOR rate plus 2.25%, and is payable monthly. Amounts borrowed under the revolving credit facility are due in May 2009. The revolving credit facility is secured by the Company’s principal mineral interests. The bank credit facility is subject to borrowing base availability, which is redetermined semiannually based on the banks’ estimates of the future net cash flows of our oil and natural gas properties. In order to obtain the revolving credit facility, loans from two officers were subordinated to the position of the bank. The Company is required under the terms of the credit facility to maintain a tangible net worth of $12,000,000, maintain a 5-to-1 ratio of income before interest, taxes, depreciation, depletion and amortization to interest expense and maintain a current asset to current liability ratio of 1-to-1, with current assets including unused amounts under the note payable.

We were in compliance with all covenants required by our credit facility as of December 31, 2006.

Notes Payable to Related Parties – In 2002, the Board of Directors authorized the Company to borrow up to $500,000 from its officers. During 2002, the Company borrowed $400,000 from two of its officers. The related notes payable bear interest at 10% per annum. The notes are secured by all mineral interests, rights and equipment of the Company but have been subordinated to the bank revolving credit facility mentioned above. The Board of Directors and the officers agreed to extend the notes to January 1, 2008, under the same terms as the original notes. Based on the borrowing rates available to the Company for bank loans, the fair value of the notes payable to officers was $400,000 at December 31, 2006 and 2005.

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Put Option – The Company granted a put option in connection with the acquisition of oil and gas properties in December 2004. Under the terms of the put option, the sellers had the right until December 1, 2006, to require the Company to repurchase the 149,658 common shares at $7.00 per share. The put option is a derivative and as such, the liability was revalued to its fair value at each balance sheet date with adjustments to fair value being recognized as gain on change in fair value of put options. This put option expired unexercised in December 2006.

NOTE 6 – ASSET RETIREMENT OBLIGATION

A reconciliation of the asset retirement obligation for the years ended December 31, 2004, 2005 and 2006 is as follows:


Balance, January 1, 2004		$ 607,200
Liabilities incurred		607,064
Accretion expense		53,729

Balance, December 31, 2004		1,267,993

Liabilities incurred		144,769
Accretion expense		102,585

Balance, December 31, 2005		1,515,347

Liabilities incurred		607,853
Accretion expense		127,132

Balance, December 31, 2006		$ 2,250,332

NOTE 7 – 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 Offerings – In August 2004, the Company completed a public offering of common stock and warrants as a unit at $6.10 per unit before underwriters’ discount and offering costs totaling $1,919,066. The Company issued 1,667,500 shares of common stock and 1,667,500 warrants to purchase common stock at $7.32 per share, through August 9, 2008. In addition, the Company issued warrants to the underwriters to purchase 145,000 shares of common stock at $9.00 per share and 145,000 warrants at $0.165 per warrant, which entitles them to purchase 145,000 shares of common stock at $7.32. Net proceeds from the offering totaled $8,252,684. These proceeds were allocated as follows: $6,470,893 were allocated to the common stock issued to investors, $1,781,791 were allocated to the warrants. The warrants had a fair value of $2,803,473 or $1.43 per share, which was determined by the Black-Scholes option pricing model using the following assumptions: volatility of 33.3%, risk-free interest rate of 3.2%, dividend yield of 0% and life of 4.0 years.

In July 2005, the Company issued 970,874 shares of common stock, valued at $10,000,000, or $10.30 per share, in a private placement. As of December 31, 2005, the Company had paid $463,062 in related offering costs. As a part of the negotiation process related to the terms of the private placement, the Company also assigned to certain of the investors call options to purchase 149,658 shares of its common stock at $8.50 per share. The call options were granted in connection with the issuance of shares of the Company’s common stock, as partial consideration for its purchase of interests in the Furhman-Mascho lease. The call terms in the option agreements provide the Company with the right to repurchase the shares issued in the Furhman-Mascho transaction at a price of $8.50 per share, at any time prior to November 1, 2006. The option agreements further provide the stockholders who received shares in that transaction the right to require the Company to repurchase its stock from them at a price of $7.00 per share (the public trading price of the common stock at the time of the Furhman-Mascho transaction) for a period of thirty days following November 1, 2006.

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The proceeds from the offering have been allocated to the common stock issued and the call options transferred based on their relative fair values and resulted in allocating $9,033,291 to the 970,874 shares of common stock and $503,647 to the 149,658 call options. The market value of the common stock on July 11, 2005 was $12.02 per share. The fair value of the call options was $4.35 per share determined by the Black-Scholes option pricing model using the following assumptions: volatility of 38.3%, risk-free interest rate of 3.6%, dividend yield of 0% and life of 1.0 years.

In May 2006, the Company issued 1,150,000 shares of common stock in a private placement for $32,246,000. The Company paid $2,457,121 in offering costs and underwriter’s fees resulting in net proceeds from the offering of $29,788,879. As part of the agreement, the Company agreed to register these shares which was completed in July 2006.

Common Stock Issued from Warrant Exercises – During the year ended December 31, 2004, warrant holders exercised 66,800 warrants with an exercise price of $5.00 per share and 11,500 warrants with an exercise price of $1.75 per share for $354,125.

During the year ended December 31, 2005, warrant holders exercised 187,800 warrants with an exercise price of $1.75 per share, 1,117,123 warrants with an exercise price of $5.00 per share, 1,665,350 warrants with an exercise price of $7.32 per share and 1,000 warrants with an exercise price of $9.00 per share for $18,113,627. The Company paid $239,006 in costs related to the call of a portion of those warrants.

During the year ended December 31, 2006, the Company issued 50,000 shares of common stock upon the exercise of warrants for proceeds of $150,000, or $3.00 per share. Additionally, during the year ended December 31, 2006, the Company issued 61,885 shares of common stock in a cashless exercise of 75,462 warrants with an exercise price of $9.00 per share and 3,461 warrants with an exercise price of $7.49 per share.

Other Issuances of Common Stock – In February 2006, the Company issued 6,200 shares of restricted common stock, valued at $181,040, or $29.20 per share, as part of the cost of a drilling rig that the Company acquired, which was placed in service in April 2006.

Additionally, during the year ended December 31, 2006, the Company issued 170,000 shares of common stock upon the exercise of options for proceeds of $640,000, or an average of $3.76 per share. As a result of these exercises, the Company will realize an additional tax benefit in the amount of $1,851,815, which was recorded against additional paid-in capital.

Warrants Issued – In connection with the July 2005 private placement, the Company committed to use its best efforts to register the shares with the SEC. The Company was unable to affect the registration within the allotted time and was required to issue 29,126 warrants on December 28, 2005. The exercise price of these warrants is $10.30 and the warrants expire December 28, 2010. The Company recognized an expense for the fair value of these warrants of $597,773 from the issuance of these warrants. The fair value of the warrants was determined using the Black-Scholes option pricing model with the following assumptions: 4.32% risk-free interest rate; 43.44% expected volatility; five year expected life and 0% dividend yield.

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company continued to be unable to affect the registration within a month from the end of the original allotted time and was required to issue an additional 29,126 warrants in January 2006. The exercise price of these warrants is $10.30 and the warrants expire in January 2011. The Company recognized an expense equal to the fair value of these warrants of $785,598 as a result of this issuance. The fair value of the warrants was determined using the Black-Scholes option pricing model with the following assumptions: 4.44% risk-free interest rate; 43.42% expected volatility; five year expected life and 0% dividend yield.

Stock purchase warrants issued and exercised during the years ended December 31, 2006, 2005 and 2004 are summarized as follows:

	2006		2005		2004

	Warrants	Weighted-Average Exercise Price	Warrants	Weighted-Average Exercise Price	Warrants	Weighted-Average Exercise Price

Outstanding at beginning of the year	368,126	$ 7.69	3,314,923	$ 4.47	1,435,723	$ 4.47
Issued	29,126	$10.30	29,126	$10.30	1,957,500	$ 7.46
Expired	-	$ -	(4,650)	$ 4.33	-	$ -
Exercised	(128,923)	$ 6.63	(2,971,273)	$ 6.10	(78,300)	$ 4.52

Outstanding at end of year	268,329	$ 8.49	368,126	$ 7.69	3,314,923	$ 6.23

Stock purchase warrants outstanding at December 31, 2006 are as follows:

Warrants Outstanding	Exercise Price	Weighted-Average Remaining Contractual Life

141,539	$ 7.49	1.6
68,538	9.00	1.6
58,252	10.30	4.0

268,329

Call Option – The Company received a call option in December 2004 in connection with the purchase of oil and gas properties. The option permits the Company to repurchase 149,658 shares of its common stock at $8.50 per share through November 1, 2006. The call option is exercisable at the Company’s discretion and was recorded as a reduction of additional paid-in capital based on its fair value of $135,777 on the date received. The fair value of the call option was determined using the Black-Scholes option pricing model with the following assumptions: 3% risk-free interest rate; 34% expected volatility; two year expected life and 0% dividend yield. The call option is part of permanent equity and will not be revalued. This call option was assigned to certain of the investors involved in the Company’s private placement offering during 2005.

NOTE 8 – EMPLOYEE STOCK OPTIONS

In March 2003, our board of directors adopted a non-qualified executive stock option plan which was subsequently approved by our shareholders at our annual meeting in July 2003, and which was amended by our shareholders at our annual meetings in 2004, 2005 and 2006. The amendments effectively increased the number of shares available under the plan to 2,500,000. There are 1,025,000 options still available for grant at December 31, 2006.

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In January 2005 and October 2005, the Company granted nonqualified stock options to directors and employees to purchase 375,000 shares and 50,000 shares of common stock at $8.30 and $20.85, respectively.

In April 2006, the Company issued 50,000 options with an original exercise price of $34.43 per share under the Company’s stock option plan. In June 2006, the Company amended these options to have an exercise price of $27.40. The original fair value of the options was $778,357, calculated using the Black-Scholes option-pricing model with the following weighted average assumptions: dividend yield of 0%, expected volatility of 43.62%, risk-free interest rate of 4.92%, and expected lives of 5 years. As a result of the amendment the fair value increased by $98,260, calculated using the Black-Scholes option-pricing model with the following weighted average assumptions: dividend yield of 0%, expected volatility of 44.27%, risk-free interest rate of 5.03%, and expected lives of 5 years.

All granted options vest at the rate of 20% each year over five years beginning one year from the date granted. A summary of the status of the stock options as of December 31, 2006 and changes during the years ended December 31, 2006, 2005 and 2004 is as follows:

	2006		2005		2004

	Options	Weighted-Average Exercise Price	Options	Weighted-Average Exercise Price	Options	Weighted-Average Exercise Price

Outstanding at beginning of the year	1,425,000	$ 5.55	1,000,000	$ 3.76	1,000,000	$ 3.76
Issued	50,000	27.40	425,000	9.78	-	-
Exercised	(170,000)	3.76	-	-	-	-

Outstanding at end of year	1,305,000	6.62	1,425,000	5.55	1,000,000	3.76

Exercisable at end of year	515,000	$ 4.75	400,000	$ 3.76	200,000	$ 3.76

Weighted average fair value of options granted during the year		$17.53		$ 3.40		$ -

The following are the weighted-average assumptions used for options granted during the years ended December 31, 2006 and 2005, with no options issued in 2004:

	2006	2005

Risk free interest rate	4.92%	3.73%
Expected life	5 Years	5 Years
Dividend yield	-	-
Volatility	44%	32%

The expected life of stock options represents the period of time that the stock options granted are expected to be outstanding based on historical exercise trends. The expected volatility is based on the historical price volatility of our common stock. 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 our anticipated cash dividend over the expected life of the stock options.

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2006, there was approximately $1,205,536 of unrecognized compensation cost related to stock options that will be recognized over a weighted average period of 2.44 years. The aggregate intrinsic value of options expected to vest at December 31, 2006 was $47,096,550. The aggregate intrinsic value of options exercisable at December 31, 2006 was $19,551,650. The year end intrinsic value is based on a December 31, 2006 closing price of $42.71. The 170,000 options exercised during 2006 had an intrinsic value of $5,075,600.

The following table summarizes information related to the Company's stock options outstanding at December 31, 2006:

		Options Outstanding

Exercise price		Number Outstanding	Weighted-Average Remaining Contractual Life (in years)	Number Exercisable

$	3.70	790,000	1.8	410,000
$	4.80	40,000	2.2	20,000
$	8.30	375,000	3.5	75,000
$	20.85	50,000	4.3	10,000
$	27.40	50,000	5.0	-

		1,305,000	2.5	515,000

NOTE 9 – RELATED PARTY TRANSACTIONS

In July 2002, the Company borrowed $400,000 from two of its officers under the terms of secured, 10% promissory notes, as more fully described in Note 5.

NOTE 10 – 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 $527,500 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.

NOTE 11 – INCOME TAXES

At December 31, 2006, the Company had alternative minimum income tax of $304,000, but had made sufficient estimated tax payments as to not have a year end taxes payable. The provision for income taxes consisted of the following:

Provision for income taxes	2006	2005	2004

Current	304,000	365,606	-
Deferred	13,673,000	5,262,520	1,397,074

	13,977,000	5,628,126	1,397,074

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Rate Reconciliation	2006	2005	2004

Tax at federal statutory rate (34%)	12,663,000	5,130,195	1,308,567
Non-deductible expenses (non-taxable income)	27,000	-	(24,493)
State tax, net of federal benefit	1,229,000	497,931	127,008
Other	58,000	-	(14,008)

	13,977,000	5,628,126	1,397,074

As of December 31, 2006, the Company had net operating loss and IDC carry forwards for federal income tax reporting purposes of $46,342,000 which, if unused, will expire in 2022, 2025 and 2026. The Company is subject to Alternative Minimum Tax (“AMT”) as a result of the deferred income that results from the regular tax treatment of intangible drilling costs. The AMT liability creates a deferred tax asset that can be used to offset any future tax liability from regular Federal income tax. The $346,744 minimum tax credit has an unlimited carryover period.

The net deferred tax liability consisted of the following:

Deferred taxes:	2006	2005	2004

Deferred tax liabilities
Property and equipment	37,448,700	11,102,307	2,163,239

Total deferred tax liabilities	37,448,700	11,102,307	2,163,239

Deferred tax assets
Stock-based compensation	493,775	203,078	158,003
Minimum tax credit	346,744	401,109	-
Operating loss and IDC carryforwards	17,285,457	3,310,511	33,246

Total deferred tax assets	18,125,976	3,914,698	191,249

Net deferred income taxes	19,322,724	7,187,609	1,971,990

NOTE 12 – SUBSEQUENT EVENTS (UNAUDITED)

Subsequent to December 31, 2006, the Company issued 125,000 shares of common stock from the exercise of 125,000 options with an exercise price of $3.70 per share, resulting in proceeds to the Company of $462,500.

Subsequent to December 31, 2006, the Company accelerated the vesting of 10,000 options. These shares would have vested on April 1, 2007. The Company will recognize the remaining fair value of $1,145 as an expense in the first quarter of 2007.

Subsequent to December 31, 2006, the Company issued 350,000 nonqualified options to officers and directors of the Company. Of the options issued, 50,000 have an exercise price of $37.35 and the remaining 300,000 have an exercise price of $38.46.

Subsequent to December 31, 2006, the Company issued 27,476 shares of common stock from the exercise of 27,476 warrants, 10,000 of which had an exercise price of $9.00 per share and 17,476 with an exercise price of $10.30 per share, resulting in proceeds to the Company of $270,003.

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Subsequent to December 31, 2006, the Company has borrowed an additional $16,200,000 on its credit facility described in Note 5.

Subsequent to December 31, 2006, the Company purchased a two story building, and an adjoining parcel of real estate, in Tulsa, Oklahoma to serve as our executive offices, for a cash payment of $1,900,000.

NOTE 13 – QUARTERLY FINANCIAL DATA (UNAUDITED)

Quarterly financial information is presented in the following summary:

	2004

	Three Months Ended

		March 31		June 30		September 30		December 31

Revenues	$	1,200,400	$	1,792,414	$	2,516,970	$	2,972,346
Operating Income		805,403		1,255,857		1,777,502		2,037,830
Net Income		262,397		520,662		803,496		865,097
Basic Net Income Per Share	$	0.04	$	0.07	$	0.10	$	0.10
Diluted Net Income Per Share		0.03		0.06		0.09		0.09

	2005

	Three Months Ended

		March 31		June 30		September 30		December 31

Revenues	$	3,914,735	$	4,628,554	$	7,937,785	$	9,362,003
Operating Income		2,815,781		3,627,958		6,422,075		7,205,037
Net Income		1,286,700		1,715,100		3,443,999		3,014,884
Basic Net Income Per Share	$	0.13	$	0.17	$	0.30	$	0.23
Diluted Net Income Per Share		0.11		0.15		0.27		0.22

	2006

	Three Months Ended

		March 31		June 30		September 30		December 31

Revenues	$	10,380,395	$	14,690,068	$	18,192,860	$	16,496,794
Operating Income		8,304,767		12,490,214		15,670,293		13,334,665
Net Income		3,582,676		6,445,224		8,006,824		5,233,244
Basic Net Income Per Share	$	0.27	$	0.47	$	0.55	$	0.36
Diluted Net Income Per Share		0.25		0.44		0.51		0.34

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

NOTE 14 – SIGNIFICANT FOURTH QUARTER ADJUSTMENTS

There were no material fourth quarter adjustments or accounting changes.

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,*		2006		2005		2004

Oil and gas revenues	$	59,760,117	$	25,843,077	$	8,482,130
Production costs		(6,453,830)		(3,832,487)		(1,975,835)
Production taxes		(3,506,347)		(1,939,739)		(629,703)
Depreciation, depletion, amortization and accretion		(8,027,231)		(2,884,089)		(1,011,602)
General and administrative (exclusive of corporate overhead)		(894,499)		(613,762)		(313,953)

Results of operations before income taxes		40,878,210		16,573,000		4,551,037
Provision for income taxes		(15,124,938)		(6,132,010)		(1,683,884)

Results of Oil and Gas Producing Operations	$	25,753,272	$	10,440,990	$	2,867,153

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 year-end prices of 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.

*For the Years Ended December 31,*	2006		2005		2004

	Oil ⁽¹⁾	Gas ⁽¹⁾	Oil ⁽¹⁾	Gas ⁽¹⁾	Oil ⁽¹⁾	Gas ⁽¹⁾

Proved Developed and Undeveloped Reserves
Beginning of year	24,867,189	31,982,079	19,550,664	9,999,541	7,050,167	3,408,754
Purchases of minerals in place	3,644,144	2,605,212	882,460	377,179	8,764,087	6,431,437
Improved recovery and development	8,952,460	10,206,642	2,546,477	19,188,896	-	640,000
Production	(900,616)	(989,991)	(441,995)	(398,611)	(195,167)	(169,002)
Revision of previous estimate	(498,904)	(1,379,743)	2,329,583	2,815,074	3,931,577	(311,648)

End of year	36,064,273	42,424,199	24,867,189	31,982,079	19,550,664	9,999,541

Proved Developed at end of year	11,566,186	29,679,976	7,885,115	22,480,279	4,721,293	4,615,265

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

ARENA RESOURCES, INC.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(Unaudited)

Standardized Measure of Discounted Cash Flows

*December 31,*		2006		2005		2004

Future cash flows	$	2,206,997,329	$	1,629,948,750	$	814,346,791
Future production costs		(436,830,228)		(281,685,991)		(171,518,828)
Future development costs		(150,553,635)		(95,765,594)		(61,975,106)
Future income taxes		(578,112,324)		(423,161,523)		(187,392,403)

Future net cash flows		1,041,501,142		829,335,642		393,460,454
10% annual discount for estimated timing of cash flows		(496,061,467)		(383,735,076)		(188,219,704)

Standardized Measure of Discounted Cash Flows	$	545,439,675	$	445,600,566	$	205,240,750

Changes in Standardized Measure of Discounted Future Net Cash Flows

*For the Years Ended December 31,*		2006		2005		2004

Beginning of the year	$	445,600,566	$	205,240,750	$	45,006,097
Purchase of minerals in place		18,153,711		33,405,120		142,824,938
Extensions, discoveries and improved recovery, less related costs		-		5,962,820		347,652
Development costs incurred during the year		328,401,017		189,832,736		5,387,638
Sales of oil and gas produced, net of production costs		(53,324,929)		(21,991,034)		(5,876,333)
Accretion of discount		58,727,964		28,467,073		4,882,064
Net changes in price and production costs		(106,369,988)		191,917,618		74,777,221
Net change in estimated future development costs		(53,640,718)		(36,307,702)		(3,187,159)
Revision of previous quantity estimates		(14,276,840)		87,175,031		42,149,044
Revision of estimated timing of cash flows		(8,582,606)		(111,387,288)		(27,509,967)
Net change in income taxes		(69,248,502)		(126,714,558)		(73,560,445)

End of the Year	$	545,439,675	$	445,600,566	$	205,240,750

United States Securities and Exchange Commission Washington, D.C. 20549

Form 10-K

Commission file number 001-31657

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

Forward Looking Statements

PART I

General

Business Development

Competitive Business Conditions

Major Customers

Governmental Regulations

Environmental Compliance and Risks

Current Employees

The loss of senior management could adversely affect us.

Risks Relating to Our Common Stock

The market price of our stock may be affected by low volume float

General Background

Proved Reserves

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

Production

Summary of Oil and Natural Gas Properties and Projects

Acreage

Production History

Productive Wells

Drilling Activity

Cost Information

Reserve Quantity Information

Standardized Measure of Discounted Future Net Cash Flows

Management’s Business Strategy Related to Properties

Other Properties and Commitments

PART II

Market for our Common Stock

Record Holders

Dividend Policy

Securities Authorized for Issuance Under Equity Compensation Plans

Recent Sales of Unregistered Securities

Issuer Repurchases

Introduction

Overview

Results of Operations

Liquidity and Capital Resources

Off-Balance Sheet Financing Arrangements

New Accounting Policies

Critical Accounting Policies and Estimates

Effects of Inflation and Pricing

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

PART III

Executive Officers and Directors

Lloyd T. Rochford – President, Chief Executive Officer and Director.

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

Charles M. Crawford – Director

Chris V. Kemendo, Jr. – Director.

Clayton E. Woodrum – Director.

New Board and Officer Appointments Subsequent to December 31, 2006.

Board Committees

Code of Ethics

Section 16(a) Beneficial Ownership Reporting Compliance –

Compensation Discussion & Analysis

Current Executive Compensation Program Elements

Base Salaries

Annual Bonuses

Perquisites

Equity-Based Compensation

Compensation Committee’s Report on Executive Compensation (1)

Compensation Committee’s Interlocks and Insider Participation

Compensation of Named Officers

Summary Compensation Table

Director Compensation

Fees and Independence

SIGNATURES

ARENA RESOURCES, INC.

INDEX TO FINANCIAL STATEMENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ARENA RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ARENA RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 – EARNINGS PER SHARE INFORMATION

ARENA RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

United States Securities and Exchange Commission
Washington, D.C. 20549

Compensation Committee’s Report on Executive Compensation ⁽¹⁾

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARENA RESOURCES, INC.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(Unaudited)

ARENA RESOURCES, INC.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(Unaudited)