# United States Securities and Exchange CommissionWashington, 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, 2005                                                    
|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                                                        
|(State or other jurisdiction of incorporation or organization)

|4920 South Lewis Avenue, Suite 107Tulsa, 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 | American 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, 2005, the aggregate market value of the common voting stock held by
non-affiliates of the issuer, based upon the closing stock price of $11.95 per share, was
approximately $98,311,108.

As
of February 28, 2006, the issuer had outstanding 13,226,702 shares of common stock
($0.001 par value).

---



|TABLE OF CONTENTS
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|Item 1           
|Item 1A          
|Item 1B          
|Item 2           
|Item 3           
|Item 4           
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|Item 5           
|Item 6           
|Item 7           
|Item 7A          
|Item 8           
|Item 9           
|Item 9A          
|Item 9B          
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|Item 10          
|Item 11          
|Item 12          
|Item 13          
|Item 14          
|
|Item 15          

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# 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: |  | Description of
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, and 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, 2005, we have
increased our proved reserves to approximately 30.2 million Boe (barrel of oil
equivalent). As of December 31, 2005, our estimated proved reserves had a pre-tax PV10
(present value of future net revenues before income taxes discounted at 10%) of
approximately $683 million and a Standardized Measure of Discounted Future Net Cash Flows
of approximately $446 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 $64
million on acquisitions and capital projects during 2003, 2004 and 2005.

---



We
have a portfolio of oil and natural gas reserves, with approximately 82% of our proved
reserves consisting of oil and approximately 18% consisting of natural gas. Of those
reserves approximately 26% of our proved reserves are classified as proved developed
producing, or PDP, approximately 4% of our proved reserves are classified as
proved developed non-producing, or PDNP, approximately 8% 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 2005, two customers were responsible for
generating 84% or more of our total oil and natural gas sales. These two customers were
Plains Marketing, L.P., accounting for approximately 12% of total sales and Navajo
Refining Company, accounting for approximately 72% of total sales. However, we believe
that the loss of either of these customers 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, 2005, we had twenty-two full-time employees, including three petroleum
engineers. 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;
|- |  | -----------------------------------------------------------------

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

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

| |  | the
level of global oil and natural gas inventories;
|- |  | ----------------------------------------------------

| |  | weather
conditions;
|- |  | -------------------

| |  | technological
advances affecting energy consumption; and
|- |  | --------------------------------------------------------

| |  | the
price and availability of alternative fuels.
|- |  | ------------------------------------------------

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

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

---



Because
a substantial percentage of our proven properties are proved undeveloped (approximately
62%), or proved developed non-producing (approximately 4%), 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 38% of our proven
reserves depend upon secondary recovery techniques to establish production.

Approximately
thirty-eight percent (38%) of our reserves for the year ended December 31, 2005 are
associated with secondary recovery projects that are either in the initial stage of
implementation or are scheduled for implementation. We anticipate that secondary recovery
will be attempted by the use of waterflood of these reserves, and the exact project
initiation dates and, by the very nature of waterflood operations, the exact completion
dates of such projects, are uncertain. In addition, the reserves associated with these
secondary recovery projects, as with any reserves, are estimates only, as the success of
any development project, including these waterflood projects, cannot be ascertained in
advance. If we are not successful in developing a significant portion of our reserves
associated with secondary recovery methods, it could have a negative impact on our
earnings and our stock price.

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

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

| |  | delays
imposed by or resulting from compliance with regulatory requirements;
|- |  | ----------------------------------------------------------------------------

| |  | pressure
or irregularities in geological formations;
|- |  | ----------------------------------------------------

| |  | shortages
of or delays in obtaining equipment and qualified personnel;
|- |  | ----------------------------------------------------------------------

| |  | equipment
failures or accidents;
|- |  | --------------------------------

| |  | adverse
weather conditions;
|- |  | ---------------------------

| |  | reductions
in oil and natural gas prices;
|- |  | -----------------------------------------

| |  | title
problems; and
|- |  | -------------------

| |  | limitations
in the market for oil and natural gas.
|- |  | --------------------------------------------------

---



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

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

| |  | the
amount of recoverable reserves;
|- |  | -----------------------------------

| |  | future
oil and natural gas prices;
|- |  | ----------------------------------

| |  | estimates
of operating costs;
|- |  | -----------------------------

| |  | estimates
of future development costs;
|- |  | --------------------------------------

| |  | estimates
of the costs and timing of plugging and abandonment; and
|- |  | ------------------------------------------------------------------

| |  | potential
environmental and other liabilities.
|- |  | ----------------------------------------------

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

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 are currently proved undeveloped reserves. The use of seismic data and
other technologies and the study of producing fields in the same area will not enable us
to know conclusively prior to drilling whether oil or natural gas will be present or, if
present, whether oil or natural gas will be present in commercial quantities. We cannot
assure you that the analogies we draw from available data from other wells, more fully
explored prospects or producing fields will be applicable to our drilling prospects.

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

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

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

| |  | abnormally
pressured formations;
|- |  | --------------------------------

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

| |  | fires
and explosions;
|- |  | ---------------------

| |  | personal
injuries and death; and
|- |  | --------------------------------

| |  | natural
disasters.
|- |  | ------------------

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

---



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

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

| |  | discharge
permits for drilling operations;
|- |  | ------------------------------------------

| |  | drilling
bonds;
|- |  | ---------------

| |  | reports
concerning operations;
|- |  | ------------------------------

| |  | the
spacing of wells;
|- |  | ---------------------

| |  | unitization
and pooling of properties; and
|- |  | ------------------------------------------

| |  | taxation.
|- |  | ---------

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

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

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

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

We
have a $50 million credit facility in place with a current borrowing base of $35 million.
If in the future we utilize this facility, the level of our indebtedness could affect our
operations in several ways, including the following:

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

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

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

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

---



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

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

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

# 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 President and Chief
Executive Officer  could have a material adverse effect on our operations. While we
have obtainedkey man life insurance policies 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 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 4,500 shares to as high as 524,600 shares. The average
volume of shares traded during the 90 days prior to December 31, 2005 was 796,854 shares
per week.

Additionally,
approximately 1,856,942 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 1,030,261 additional shares of common stock
that are currently restricted, will soon be capable of being resold under Rule
144.

Finally,
as of December 31, 2005 there are warrants outstanding to purchase 368,126 shares of
common stock, as well as options to purchase 1,425,000 shares of common stock (of which
options to acquire 400,000 shares are currently exercisable, with 400,000 options vesting
over the next two and one-half 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: |  | Description of
Property
|------- |  | -----------------------

# 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, 2005, our proved reserves have grown
to 30,197,536 Boe, at an average acquisition/drilling cost of $2.21 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 ($66,748,047),
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
(30,197,536).

As
of December 31, 2005, our estimated proved reserves had a pre-tax PV10 value of
approximately $683 million and a Standardized Measure of Discounted Future Cash Flows of
approximately $446 million, approximately 31% of which came from properties located in New
Mexico, approximately 56% from our properties in Texas, approximately 9% from our
properties in Oklahoma and approximately 4% from our properties in Kansas. We spent
approximately $64 million on capital projects during 2003, 2004 and 2005. We expect to
further develop these properties through additional drilling. Our capital budget for 2006
is approximately $61 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, 2005.

|Geographic Area | Oil(Bbl) | Natural Gas(Mcf) | Total(Boe) | Pre-Tax PV10 Value | Standardized Measure of Discounted Future Net Cash Flows
|--------------- | -------- | ---------------- | ---------- | ------------------ | --------------------------------------------------------
|                |          |                  |            |                    |                                                         
|New Mexico      |          |                  |            | 9,312,749          |                                                         
|Texas           |          |                  |            | 12,375,123         |                                                         
|Oklahoma        |          |                  |            | 3,179,317          |                                                         
|Kansas          |          |                  |            | --                 |                                                         
|                |          |                  |            |                    |                                                         
|Total           |          |                  |            | 24,867,189         |                                                         
|                |          |                  |            |                    |                                                         

# Proved Reserves

Our
30,197,536 Boe of proved reserves, which consist of approximately 82% oil and 18% natural
gas, are summarized below as of December 31, 2005, 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, 2005, New Mexico proved reserves had a net pre-tax PV10 value of $216.5
million and Standardized Measure of Discounted Future Net Cash Flows of $136.6 million,
our proved reserves in Texas had a net pre-tax PV10 value of $380.4 million and
Standardized Measure of Discounted Future Net Cash Flows of $251.5 million, our proved
reserves in Oklahoma had a net pre-tax PV10 value of $62.3 million and a Standardized
Measure of Discounted Future Net Cash Flows of $41.7 million and our proved reserves in
Kansas had a net pre-tax PV10 value of $23.9 million and a Standardized Measure of
Discounted Future Net Cash Flows of $15.8 million.

As
of December 31, 2005, approximately 26% of the 30.2 million Boe of proved reserves have
been classified as proved developed producing, or PDP. Proved developed
non-producing, or PDNP reserves constitute approximately 4%, proved developed
behind-pipe PDBP reserves constitute approximately 8% and proved undeveloped,
or PUD, reserves constitute approximately 62%, of the proved reserves as of
December 31, 2005.

Approximately
thirty-eight percent (38%) of our reserves for the year ended December 31, 2005 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.

Total
proved reserves had a net pre-tax PV10 value as of December 31, 2005 of approximately $683
million and a Standardized Measure of Discounted Future Net Cash Flows of approximately
$446 million, 25.8% or $145.5 million and $94.5, respectively, of which is associated with
the PDP reserves. An additional $39.2 million and $25.9 million, respectively, is
associated with the PDNP reserves and $53.1 million and $34.9 million, respectively, is
associated with PDBP reserves ($237.8 million and $155.3 million, respectively, for total
proved developed reserves, or 38.5% of total proved reserves pre-tax PV10 value).
The remaining $445.2 million and $290.4 million, respectively, is associated with PUD
reserves.

---



Our
proved reserves as of December 31, 2005 are summarized in the table below.

|              | Oil(Bbl)  |  | Gas(Mcf)  |  | Total(Boe) |  | % of TotalProved |  |   | Pre-taxPV10(In thousands) |  |   | Standardized Measure of Discounted Future Net Cash Flows |  |   | Future CapitalExpenditures(In thousands)
|------------- | --------- |  | --------- |  | ---------- |  | ---------------- |  | - | ------------------------- |  | - | -------------------------------------------------------- |  | - | ----------------------------------------
|New Mexico:   |           |  |           |  |            |  |                  |  |   |                           |  |   |                                                          |  |   |                                         
|PDP           | 3,165,117 |  | 2,976,114 |  | 3,661,136  |  | 12%              |  | $ | 59,972                    |  | $ | 37,856                                                   |  | $ | -                                       
|PDNP          | 59,301    |  | 80,056    |  | 72,644     |  | 0%               |  |   | 2,600                     |  |   | 1,641                                                    |  |   | 318                                     
|PDBP          | 326,902   |  | 250,734   |  | 368,691    |  | 1%               |  |   | 7,438                     |  |   | 4,695                                                    |  |   | 33                                      
|PUD           | 5,761,429 |  | 1,615,105 |  | 6,030,613  |  | 20%              |  |   | 146,456                   |  |   | 92,447                                                   |  |   | 14,431                                  
|              |           |  |           |  |            |  |                  |  |   |                           |  |   |                                                          |  |   |                                         
|Total Proved: | 9,312,749 |  | 4,922,009 |  | 10,133,084 |  | 33%              |  | $ | 216,466                   |  | $ | 136,639                                                  |  | $ | 14,782                                  
|              |           |  |           |  |            |  |                  |  |   |                           |  |   |                                                          |  |   |                                         

|Texas:        |            |  |            |  |            |  |     |  |   |         |  |   |         |  |   |       
|------------- | ---------- |  | ---------- |  | ---------- |  | --- |  | - | ------- |  | - | ------- |  | - | ------
|PDP           | 2,977,483  |  | 1,704,167  |  | 3,261,511  |  | 11% |  | $ | 68,816  |  | $ | 45,507  |  | $ | -     
|PDNP          | 702,863    |  | 383,558    |  | 766,789    |  | 3%  |  |   | 28,852  |  |   | 19,079  |  |   | 4,160 
|PDBP          | -          |  | 13,701,828 |  | 2,283,638  |  | 8%  |  |   | 45,703  |  |   | 30,223  |  |   | 4,140 
|PUD           | 8,694,777  |  | 4,103,076  |  | 9,378,623  |  | 31% |  |   | 236,986 |  |   | 156,716 |  |   | 65,209
|              |            |  |            |  |            |  |     |  |   |         |  |   |         |  |   |       
|Total Proved: | 12,375,123 |  | 19,892,629 |  | 15,690,561 |  | 53% |  | $ | 380,357 |  | $ | 251,525 |  | $ | 73,509
|              |            |  |            |  |            |  |     |  |   |         |  |   |         |  |   |       

|Oklahoma:     |           |  |         |  |           |  |     |  |   |        |  |   |        |  |   |      
|------------- | --------- |  | ------- |  | --------- |  | --- |  | - | ------ |  | - | ------ |  | - | -----
|PDP           | 525,336   |  | 108,825 |  | 543,474   |  | 3%  |  | $ | 8,924  |  | $ | 5,968  |  | $ | -    
|PDNP          | 128,113   |  | -       |  | 128,113   |  | 0%  |  |   | 3,257  |  |   | 2,178  |  |   | -    
|PUD           | 2,525,868 |  | 215,621 |  | 2,561,805 |  | 7%  |  |   | 50,102 |  |   | 33,509 |  |   | 6,575
|              |           |  |         |  |           |  |     |  |   |        |  |   |        |  |   |      
|Total Proved: | 3,179,317 |  | 324,446 |  | 3,233,392 |  | 10% |  | $ | 62,283 |  | $ | 41,655 |  | $ | 6,575
|              |           |  |         |  |           |  |     |  |   |        |  |   |        |  |   |      

|Kansas:       |   |  |           |  |           |  |    |  |   |        |  |   |        |  |   |    
|------------- | - |  | --------- |  | --------- |  | -- |  | - | ------ |  | - | ------ |  | - | ---
|PDP           | - |  | 1,962,997 |  | 327,166   |  | 1% |  | $ | 7,761  |  | $ | 5,135  |  | $ | -  
|PDNP          | - |  | 1,312,000 |  | 218,667   |  | 1% |  |   | 4,486  |  |   | 2,968  |  |   | -  
|PUD           | - |  | 3,567,998 |  | 594,666   |  | 2% |  |   | 11,608 |  |   | 7,679  |  |   | 900
|              |   |  |           |  |           |  |    |  |   |        |  |   |        |  |   |    
|Total Proved: | - |  | 6,842,995 |  | 1,140,499 |  | 4% |  | $ | 23,855 |  | $ | 15,782 |  | $ | 900
|              |   |  |           |  |           |  |    |  |   |        |  |   |        |  |   |    

|Total:        |            |  |            |  |            |  |      |  |   |         |  |   |         |  |   |       
|------------- | ---------- |  | ---------- |  | ---------- |  | ---- |  | - | ------- |  | - | ------- |  | - | ------
|PDP           | 6,667,936  |  | 6,752,103  |  | 7,793,287  |  | 26%  |  | $ | 145,473 |  | $ | 94,466  |  | $ | -     
|PDNP          | 890,277    |  | 1,775,614  |  | 1,186,213  |  | 4%   |  |   | 39,195  |  |   | 25,866  |  |   | 4,478 
|PDBP          | 326,902    |  | 13,952,562 |  | 2,652,329  |  | 9%   |  |   | 53,141  |  |   | 34,918  |  |   | 4,173 
|PUD           | 16,982,074 |  | 9,501,800  |  | 18,565,707 |  | 62%  |  |   | 445,152 |  |   | 290,351 |  |   | 87,115
|              |            |  |            |  |            |  |      |  |   |         |  |   |         |  |   |       
|Total Proved: | 24,867,189 |  | 31,982,079 |  | 30,197,536 |  | 100% |  | $ | 682,961 |  | $ | 445,601 |  | $ | 95,766
|              |            |  |            |  |            |  |      |  |   |         |  |   |         |  |   |       

# 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 OilReservesDeveloped (Bbls) |  | Estimated GasReservesDeveloped (Mcf) |  | Total Boe  |  |   | EstimatedDevelopment Costs
|---- | ------------------------------------- |  | ------------------------------------ |  | ---------- |  | - | --------------------------
|     |                                       |  |                                      |  |            |  |   |                           
|2006 | 11,615,519                            |  | 6,643,650                            |  | 12,722,794 |  | $ | 52,044,584                
|2007 | 5,366,554                             |  | 2,858,155                            |  | 5,842,913  |  |   | 35,070,440                
|     |                                       |  |                                      |  |            |  |   |                           
|     | 16,982,073                            |  | 9,501,805                            |  | 18,565,707 |  | $ | 87,115,024                
|     |                                       |  |                                      |  |            |  |   |                           

# Production

Our
estimated average daily production for the month of December, 2005, is summarized below.
These tables indicate the percentage of our estimated December 2005 average daily
production of 2,050 Boe/d attributable to each state and to oil versus natural gas
production.

|State      |  | AverageDailyProduction |  | Oil    |  | NaturalGas
|---------- |  | ---------------------- |  | ------ |  | ----------
|New Mexico |  | 29.48%                 |  | 25.46% |  | 4.02%     
|Texas      |  | 60.30%                 |  | 55.32% |  | 4.98%     
|Oklahoma   |  | 8.05%                  |  | 7.48%  |  | 0.57%     
|Kansas     |  | 2.18%                  |  | 0.00%  |  | 2.18%     
|           |  |                        |  |        |  |           
|Total      |  | 100%                   |  | 88%    |  | 12%       

# 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 a 82.24% working
interest and a 67.6% net revenue interest in this lease primarily from EnerQuest Oil and
Gas, Ltd., an unaffiliated company, for a cash payment of $10,008,440. 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. Although the Purchase and Sales Agreement transferred
the revenue and the related operating costs from East Hobbs to us 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 operations of East
Hobbs operations were included in our results of operations from May 7, 2004.
Revenues and operating costs for the months of March and April were estimated and treated
as adjustments to the purchase price. This lease covers approximately 920 acres. There are
currently 28 producing wells. We believe this property can support a number of additional
wells, four of 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. This lease was acquired
from Permian Resources Holding, Inc., an unaffiliated company, for a cash payment of
$900,000. The remaining working interest is owned by unaffiliated parties. There are
currently 40 producing wells on this lease. We believe this property can support a number
of additional wells, six of which are included in our estimate of PUD. 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 22
producing wells. This lease was acquired from United Resources, L.P., an unaffiliated
company, for a cash payment of $500,000. 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 will require additional volumes of water to support the
waterflood expansion. A sufficient and economical source of water has been identified and
contracted for. A water line of approximately four miles in length will be constructed
across Bureau of Land Management lands to transport the water to the North Benson Queen
Unit. Permit applications have been submitted to the Bureau of Land Management and we are
awaiting final approval. The construction of the water line should require approximately
thirty days at a cost of $250,000. The development of the North Benson Queen Unit
waterflood is scheduled for 2006 at estimated costs of $4,800,000.

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 from four entities; Paul D.
Friemel & Assoc, Inc., Compostella Oil Company, Redco Oil & Gas Inc. and Terry N.
Stevens, Inc., all unaffiliated companies. The purchase price, including acquisition
costs, was $10,966,495 and consisted of $9,667,381 of cash paid to the sellers, $44,421 in
cash acquisition costs, 179,658 shares of the Companys common stock, valued at
$1,260,091, or $7.00 per share, and the issuance of put and call options with a net value
of $24,602. These leases cover approximately 11,300 acres. We believe this property can
support a number of additional wells, 147 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. This lease was acquired from Durango
Operating Company, Inc. an unaffiliated company, for a cash payment of $750,000. 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 $1,050,000 cost thereof) is
included as PUD in our reserve report. This lease consists of approximately 1,697 acres
and is held by production.

West
San Andres Unit  Yoakum County, Texas. In October 2003 we acquired a 100%
working interest and a 79.60% net revenue interest in this lease from Permian Resources,
Inc. an unaffiliated company, for a cash payment of $500,000. The lease covers
approximately 1,200 acres, and currently has 12 producing wells. We believe this property
can support a number of additional wells, four of which are included in our estimate of
PUD. This lease is held by production.

Dodson
Lease  Montague County, Texas. We purchased a 100% working interest and an
81.25% net revenue interest in this lease in June 2002. This lease was acquired from
Nocona minerals Partnership, an unaffiliated company, for a cash payment of $200,000.
There are currently three producing wells and nine other wells on this approximately 570
acre lease, all of which 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 was acquired from Bass Petroleum, Inc., an
unaffiliated company, for a cash payment of $735,000. This lease has approximately 2,120
acres and 11 producing wells. We believe this property could support a number of
additional wells, to of 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.
This lease was acquired from Ensign Operating Company, an unaffiliated company, for a cash
payment of $827,500. The lease consists of approximately 489 acres and has seven producing
wells. We believe this property could support a number of additional wells, two of 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 six producing
wells, and we believe there are up to three additional drilling locations on these leases.
The Hanes lease contains approximately 640 acres and two producing wells. We believe this
property could support a number of additional wells, three of 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.

The
Midwell, Appleby, Smaltz, Hanes and Roy Hanes leases were acquired from Burk Royalty Co.,
Ltd., R.A. Kimball Property Co., Ltd. and Kimball Family Resources, Ltd., all unaffiliated
companies. The cost of these leases was $550,179, with $100,000 paid in cash and the
balance paid through our issuance of 99,885 shares of our common stock valued at $4.00 per
share (the then current market value), and the issuance of put and call options with a net
value to the sellers of $50,639.

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).

In
2002, we successfully drilled one well at a cost of approximately $153,000 to drill,
complete and connect to the pipeline and thus will have reached payout when we recover
this amount from production. After payout, Bird Creek Resources, Inc. will own the
remaining 25% working interest.

---



On
March 20, 2002, we entered into a joint venture agreement with Petro Consultants, Inc., to
drill and operate the well on the above-mentioned property. Under the terms of the
agreement, Petro purchased 27% of the working interest in the well for $88,200. On May 20,
2002, after the well was successfully drilled, we issued 70,000 shares of common stock
(valued at $1.26 per share) to Petro to repurchase the 27% working interest in the well.

In
February 2004, we successfully drilled one additional well on this acreage at a cost of
approximately $159,000 to drill, complete and connect to the pipeline and thus will have
reached payout when we recover this amount from production. After payout, Bird Creek
Resources, Inc. will own the remaining 25% working interest.

In
November 2004, we completed the installation of a pipeline from our Koehn lease to a
gatherer/purchased pipeline. Total cost on installation of the pipeline was approximately
$144,000. The installation of this pipeline was necessary to be able to begin producing
from our wells in that area. Production started on December 11, 2004.

Schmidt
Unit  Gray County, Kansas. During 2004 we leased an additional 640 acres
offsetting our Koehn/Rexford Unit for a total of approximately $8,582. In November 2004,
we successfully drilled one well on this acreage at a cost of approximately $183,520 to
drill, complete and connect to the pipeline. We began producing from this well on December
23, 2004.

Beals
Prospect  Comanche County, Kansas. In July 2003 we acquired a 100% working
interest and an 80.5% net revenue interest in this lease, consisting of 1,560 acres. This
lease was acquired from Bengalia Land and Cattle Company, an unaffiliated party, for a
cash payment of $60,000. These leases will expire in April 2006; however, the Company is
in the process of extending the leases an additional year.

Syracuse
Prospect  Hamilton County, Kansas. During 2005 we leased 15,680 acres for a
total of approximately $433,134. These leases provide us a 100% working interest and an
81% net revenue interest. During 2005, we drilled two wells, both of which are still under
analysis and are being considered for completion. Additionally, we sold 41.25% of the
working interest in these wells, for total proceeds of $340,000.

Rocky
Prospect  Comanche County, Kansas. During 2005 we leased 4,160 acres for a total
of approximately $141,412. These leases provide us a 100% working interest and an 80% net
revenue interest. During 2005, we drilled two wells on this property. One well was
completed and put into production in December 2005. We sold a 41.25% working interest in
this well for total proceeds of $170,000. The second well was drilled successfully but was
pending completion at December 31, 2005. We sold a 50% working interest in this well for
proceeds of $215,000, plus a commitment to pay a determined amount if the well was
successful, dependant upon what zone or zones the well was to be completed in.

# Acreage

The
following table summarizes gross and net developed and undeveloped acreage at December 31,
2005 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        
|           |                   |  |                     |  |              
|New Mexico | 4,960             |  | 3,294               |  | --           
|Texas      | 15,687            |  | 11,941              |  | --           
|Oklahoma   | 5,529             |  | 4,122               |  | --           
|Kansas     | 3,520             |  | 2,816               |  | 20,600       
|           |                   |  |                     |  |              
|Total      | 26,696            |  | 22,174              |  | 20,600       
|           |                   |  |                     |  |              

# Production History

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

|                                  | Year Ended December 31,
|--------------------------------- | -----------------------
|                                  |                        
|                                  |                        
|Oil production (Bbls)             |                        
|Natural gas production (Mcf)      |                        
|Total production (Boe)            |                        
|Daily production (Boe/d)          |                        
|Average sales price:              |                        
|Oil (per Bbl)                     | $                      
|Natural gas (per Mcf)             |                        
|Total (per Boe)                   |                        
|Average production cost (per Boe) | $                      

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, 2005, 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      
|New Mexico | 90        |  | 59        |  | -          
|Texas      | 223       |  | 169       |  | -          
|Oklahoma   | 26        |  | 21        |  | -          
|Kansas     | -         |  | -         |  | 7          
|           |           |  |           |  |            
|Total      | 339       |  | 249       |  | 7          
|           |           |  |           |  |            

---



# Drilling Activity

During
2005 we completed the drilling of forty-six wells. Thirty-six wells were drilled on our
Fuhrman Mascho properties in Andrews County, Texas. Six of the wells were drilled in
Kansas, two in Gray County, Kansas, offsetting our existing wells there and four in
Hamilton and Greeley County, Kansas on acreage acquired during 2005. The four wells in
Hamilton and Greeley Counties were exploratory wells. Three wells were drilled on our East
Hobbs property in Lea County, New Mexico. One well was drilled on our Eva South property
in Texas 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 $8.92 in 2003, $8.85 in 2004 and $7.54 in 2005. 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, 2003, 2004 and 2005 are shown below.

|                                   | For the Years Ended December 31,
|---------------------------------- | --------------------------------
|                                   |                                 
|                                   |                                 
|                                   |                                 
|Acquisition of proved properties   | $                               
|Acquisition of unproved properties |                                 
|Exploration costs                  |                                 
|Development costs                  |                                 
|                                   |                                 
|Total Costs Incurred               | $                               
|                                   |                                 

(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, 2002 | 4,113,936                     |            | 3,187,757 
|                           | Purchase of minerals in place | 3,175,357  |            | 570,924         
|                           | Extensions and discoveries    | 18,066     |            | 229,626         
|                           | Production                    | (117,646)  |            | (67,329)        
|                           | Revisions of estimates        | (139,546)  |            | (512,224)       
|                           |                               |            |            |                 
|                           |                               |            |            |                 
|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
|                           |                               |            |            |                 

Our
proved oil and natural gas reserves are shown below.

|                  |             |  | For the Years Ended December 31,
|----------------- | ----------- |  | --------------------------------
|                  |             |  | 2003                            
|                  |             |  |                                 
|Oil (Bbls)        |             |  |                                 
|                  | Developed   |  | 1,580,521                       
|                  | Undeveloped |  | 5,469,646                       
|                  |             |  |                                 
|                  | Total       |  | 7,050,167                       
|                  |             |  |                                 
|                  |             |  |                                 
|Natural Gas (Mcf) |             |  |                                 
|                  | Developed   |  | 1,612,738                       
|                  | Undeveloped |  | 1,796,016                       
|                  |             |  |                                 
|                  | Total       |  | 3,408,754                       
|                  |             |  |                                 
|                  |             |  |                                 
|Total (Boe)       |             |  |                                 
|                  | Developed   |  | 1,849,311                       
|                  | Undeveloped |  | 5,768,972                       
|                  |             |  |                                 
|                  | Total       |  | 7,618,283                       
|                  |             |  |                                 

# 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,                                             |   | 2005          |  |  |   | 2004          |  |  |   | 2003         | 
|-------------------------------------------------------- | - | ------------- |  |  | - | ------------- |  |  | - | ------------ | 
|                                                        
|Future cash flows                                        | $ | 1,629,948,750 |  |  | $ | 814,346,791   |  |  | $ | 218,026,254  | 
|Future production costs                                  |   | (281,685,991) |  |  |   | (171,518,828) |  |  |   | (64,157,199) | 
|Future development costs                                 |   | (95,765,594)  |  |  |   | (61,975,106)  |  |  |   | (13,609,384) | 
|Future income taxes                                      |   | (423,161,523) |  |  |   | (187,392,403) |  |  |   | (45,778,941) | 
|                                                        
|Future net cash flows                                    |   | 829,335,642   |  |  |   | 393,460,454   |  |  |   | 94,480,730   | 
|10% annual discount for estimated timing of cash   flows |   | (383,735,076) |  |  |   | (188,219,704) |  |  |   | (49,474,633) | 
|                                                        
|Standardized Measure of Discounted Cash Flows            | $ | 445,600,566   |  |  | $ | 205,240,750   |  |  | $ | 45,006,097   | 
|                                                        

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,                                    |   | 2005          |  |  |   | 2004         |  |  |   | 2003        | 
|------------------------------------------------------------------- | - | ------------- |  |  | - | ------------ |  |  | - | ----------- | 
|                                                                   
|Beginning of the year                                               | $ | 205,240,750   |  |  | $ | 45,006,097   |  |  | $ | 27,997,824  | 
|Purchase of minerals in place                                       |   | 33,405,120    |  |  |   | 142,824,938  |  |  |   | 21,333,720  | 
|Extensions, discoveries and improved recovery, less   related costs |   | 5,962,820     |  |  |   | 347,652      |  |  |   | 691,469     | 
|Development costs incurred during the year                          |   | 189,832,736   |  |  |   | 5,387,638    |  |  |   | 320,102     | 
|Sales of oil and gas produced, net of production costs              |   | (21,991,034)  |  |  |   | (5,876,333)  |  |  |   | (2,302,405) | 
|Accretion of discount                                               |   | 28,467,073    |  |  |   | 4,882,064    |  |  |   | 3,012,793   | 
|Net changes in price and production costs                           |   | 191,917,618   |  |  |   | 74,777,221   |  |  |   | 8,222,075   | 
|Net change in estimated future development costs                    |   | (36,307,702)  |  |  |   | (3,187,159)  |  |  |   | 39,219      | 
|Revision of previous quantity estimates                             |   | 87,175,031    |  |  |   | 42,149,044   |  |  |   | (53,098)    | 
|Revision of estimated timing of cash flows                          |   | (111,387,288) |  |  |   | (27,509,967) |  |  |   | (5,468,732) | 
|Net change in income taxes                                          |   | (126,714,558) |  |  |   | (73,560,445) |  |  |   | (8,786,870) | 
|                                                                   
|End of the Year                                                     | $ | 445,600,566   |  |  | $ | 205,240,750  |  |  | $ | 45,006,097  | 
|                                                                   

# 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 29,696 gross (22,174 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, 2005, we owned interests in approximately 20,600 gross undeveloped acres
(16,645 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 2006 is approximately $61
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 2006 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, 2005, our oil
and gas production costs per Boe averaged $7.54 and general and administrative costs
averaged $2.69 per Boe produced.

# Other Properties and
Commitments

We
currently lease our principal executive offices in Tulsa, Oklahoma. At December 31, 2005,
the lease was for approximately 3,224 square feet of office space, at an annual rental of
$30,000. This lease is set to expire at December 31, 2006. The current 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 15, 2005. 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 2006. 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 1,500,000 to 2,000,000. Additionally, due to the fact that under existing rules of
the American Stock Exchange, essentially any issuance of common stock to employees or
consultants must be approved by the stockholders, at the meeting a proposal was presented
to allow for the issuance of up to 50,000 shares of common stock to employees or
consultants as compensation for services. This matter was voted on pursuant to the
discretionary authority granted under the proxies solicited for the annual meeting. The
following reflects the votes cast for each matter voted on at the annual meeting:

---



|                                    |  | Votes for  |  |  |  | Votes against |  |  |  | Abstain | 
|----------------------------------- |  | ---------- |  |  |  | ------------- |  |  |  | ------- | 
|                                    |  |            |  |  |  |               |  |  |  |         | 
|Lloyd T. Rochford                   |  | 10,747,316 |  |  |  | -             |  |  |  | 629,505 | 
|Stanley M. McCabe                   |  | 11,194,710 |  |  |  | -             |  |  |  | 182,111 | 
|Charles M. Crawford                 |  | 11,278,076 |  |  |  | -             |  |  |  | 98,745  | 
|Chris V. Kemendo, Jr.               |  | 10,776,131 |  |  |  | -             |  |  |  | 600,690 | 
|Clayton E. Woodrum                  |  | 11,210,085 |  |  |  | -             |  |  |  | 166,536 | 
|                                    |  |            |  |  |  |               |  |  |  |         | 
|Amendment to option plan            |  | 10,470,309 |  |  |  | 872,422       |  |  |  | 34,090  | 
|                                    |  |            |  |  |  |               |  |  |  |         | 
|Adoption of Stock Compensation Plan |  | 10,470,309 |  |  |  | 872,422       |  |  |  | 34,090  | 

---



# 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
April 15, 2003, our common stock has been traded on the American Stock Exchange, under the
symbol ARD. Prior to that time, our common stock traded on the OTC Bulletin
Board. The following table shows the high and low sales prices for each quarter since
listing on the American Stock Exchange, and the high and low bid prices prior to such
time, during the last three years.

|Period                                      |   | High Sale or Bid |  |  |   | Low Sale or Bid | 
|------------------------------------------- | - | ---------------- |  |  | - | --------------- | 
|1st Quarter 2003                            | $ | 4.35             |  |  | $ | 4.25            | 
|2nd Quarter 2003                            |   | 5.99             |  |  |   | 4.35            | 
|3rd Quarter 2003                            |   | 5.82             |  |  |   | 5.45            | 
|4th Quarter 2003                            |   | 6.10             |  |  |   | 5.40            | 
|                                            |   |                  |  |  |   |                 | 
|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 (throughFebruary 28, 2006) | $ | 36.99            |  |  | $ | 26.90           | 

# Record Holders

As
of February 28, 2006, there are approximately 4,167 holders of record of our common stock.
Approximately 17%, or 2,230,200 shares of the 13,226,702 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 meeting in 2004 and in 2005. 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, 2005, we issued 37,250 shares of our common stock upon
the exercise of previously issued warrants at either $3.00 per share or $9.00 per share.
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.

During
the three months ended December 31, 2005, we issued 29,126 warrants to purchase our common
stock at an exercise price of $10.30 per share. These warrants 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, 2005.

|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, 2005, 2004, 2003, 2002 and 2001. 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,
|--------------------------------------------------- | -------------------------------
|                                                    |                                
|                                                    | 2005                           
|                                                    |                                
|Statement of Operations Data:                       |                                
|Revenues                                            | $                              
|Cost of revenues                                    |                                
|Depreciation, depletion and   amortization          |                                
|Accretion                                           |                                
|General and administrative                          |                                
|Net income                                          |                                
|Preferred stock dividends                           |                                
|Income (Loss) attributable to   common shareholders |                                
|                                                    |                                
|Basic income (loss) per   common share              | $                              
|Diluted income (loss) per   common share            |                                

---



|                                                 | As of December 31,
|------------------------------------------------ | ------------------
|                                                 |                   
|                                                 | 2005              
|                                                 |                   
|Balance Sheet Data:                              |                   
|Current assets                                   | $                 
|Oil and gas properties subject   to amortization |                   
|Total assets                                     |                   
|Total current liabilities                        |                   
|Total long-term liabilities                      |                   
|Total Stockholders Equity                        |                   

|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 four 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 $34.3 million in
acquisitions and enhancements in 2005, following total capital expenditures of
approximately $26 million in 2004 and approximately $4 million in 2003.

Our
capital budget for 2006 is approximately $61 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,
|----------------------------- | --------------------------------------------------- | - | --------------------------------
|                              |                                                     |  
|                              |                                                     |   | 2003                            
|                              |                                                     |   |                                 
|Net production:               |                                                     |   |                                 
|                              | Oil (Bbls)                                          |   | 117,646                         
|                              | Natural gas (Mcf)                                   |   | 67,329                          
|                              |                                                     |   |                                 
|Net sales:                    |                                                     |   |                                 
|                              | Oil                                                 | $ | 3,418,480                       
|                              | Natural gas                                         |   | 246,997                         
|                              |                                                     |   |                                 
|Average sales price:          |                                                     |   |                                 
|                              | Oil (per Bbl)                                       | $ | 29.06                           
|                              | Natural gas (per Mcf)                               |   | 3.67                            
|                              |                                                     |   |                                 
|Production costs and expenses |                                                     |   |                                 
|                              | Oil and gas production costs                        | $ | 1,149,136                       
|                              | Production taxes                                    |   | 269,563                         
|                              | Depreciation, depletion and    amortization expense |   | 360,282                         
|                              | Accretion expense                                   |   | 32,212                          
|                              | General and administrative    expenses              |   | 778,774                         

---



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 2003 to $6.72 in
2004. 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 to which the financing expenses relate 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.

---



Year Ended December 31,
2004 Compared to Year Ended December 31, 2003

Oil
and natural gas sales. Oil and natural gas sales revenue increased approximately $4.82
million to $8.48 million in 2004. Oil sales increased $4.24 million and natural gas sales
increased $575,000. The oil sales increase was caused by a sales volume increase of 77,520
barrels in 2004, and a 35% increase in the average realized per barrel oil price from
$29.06 in 2003 to $39.25 in 2004. 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 101,673 Mcf in 2004 and a 32% increase
in the average realized natural gas price per Mcf from $3.67 in 2003 to $4.86 in 2004.
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 $26 million of capital expenditures during 2004, of which approximately $21 million
were related to our acquisition of the East Hobbs and Fuhrman Mascho properties.

Oil
and gas production costs. Our aggregate oil and gas production costs increased from
$1,149,136 in 2003 to $1,975,835 2004, although such expenses on a Boe basis declined
slightly from $8.92 in 2003 to $8.85 in 2004. 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 2003 in our operations for a
full year in 2004; acquiring new properties and accounting for them for a portion of the
year in 2004 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% during 2003 and remained steady at 7% in 2004. 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 $651,320 to $1,011,602 in 2004. The increase was a result of an increase in
the average depreciation, depletion and amortization rate from $2.79 per Boe during 2003
to $4.53 per Boe during 2004. 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 $96,076
to $874,850 during 2004. This increase was primarily related to increases in compensation
expense associated with an increase in personnel required to administer our growth, legal
fees of $31,150, annual listing fees of $18,700, $16,095 in fees paid to Lee Keeling for
2003 reserve reports, fees related to obtaining our credit facility and letters of credit
and directors fees.

Interest
expense. Interest expense increased $117,138 to $155,936 in 2004. The increase was due
to higher amounts of debt being outstanding during periods of the year in 2004.

Income
tax expense. Our effective tax rate was 37% during 2004 and 37% during 2003.

---



Cumulative
change in accounting principle. Effective January 1, 2003, we adopted the provisions
of SFAS No. 143, Accounting for Asset Retirement Obligations. This statement
generally applies to legal obligations associated with the retirement of long-lived assets
and requires us to recognize the fair value of asset retirement obligations in our
financial statements by capitalizing that cost as a part of the cost of the related asset.
This statement applies directly to the plug and abandonment liabilities associated with
our net working interest in well bores. The additional carrying amount is depleted over
the estimated lives of the properties. The discounted liability is based on historical
abandonment costs in specific areas and is accreted at the end of each accounting period
through charges to accretion expense. The liability is discounted using a credit-adjusted
risk-free rate of approximately 8.08%. If the obligation is settled for other than the
carrying amount, a gain or loss is recognized on settlement. Upon adoption of SFAS No.
143, we recorded an increase to our discounted abandonment liability of $236,718,
increased proved property cost by $217,878, and recognized a one-time cumulative effect
charge of $11,813 (net of a related tax effect of $7,027). The effect of adopting this
accounting principle was a $24,873 after tax decrease in net income during 2003.

Net
income. Net income increased from $670,143 for 2003 to $2,451,652 for 2004. 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, our initial public offering of stock in 2001, private equity offerings of our
stock and warrants and our secondary offering of common stock and warrants which we closed
in August 2004.

Credit
Facility. On April 14, 2004, we established a $15,000,000 credit facility with our
principal lenders with an $8,500,000 initial borrowing base. In April 2005, we entered
into an agreement that increased the facility to $50,000,000, with an increased borrowing
base of $35,000,000. Any increases in the borrowing base are subject to written consent by
the financial institution. The interest rate is a floating rate equal to the 30, 60 or 90
day LIBOR rate plus 2.25%, currently 7.11% per annum, and is payable monthly. Amounts
borrowed under the revolving credit facility are due on April 30, 2008. The revolving
credit facility is secured by our principal mineral interests. In order to obtain the
revolving credit facility, loans from two officers were subordinated to the position of
the bank. We are 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. At December 31, 2005, no amounts were outstanding
under this credit facility, though $299,029 is 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, 2005, we generated $28,467,736 from
operating activities, financed $37,763,518 through proceeds from the sale of stock and
warrants, and $400,000 from debt obligations owed to two officers, for a total of
$66,631,254. We primarily used this cash generation to fund our capital expenditures and
development aggregating $44,745,430 over the three years. At December 31, 2005, we had
cash on hand of $4,317,114 and working capital of $1,083,664, compared to December 31,
2004 when our cash was $1,253,969 and working capital of $657,758.

We
continually evaluate our capital needs and compare them to our capital resources. Our
budgeted capital expenditures for 2006 are approximately $61,000,000 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
2006, 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. The following table summarizes our future estimated
principal and minimum debt and lease payments for periods subsequent to December 31, 2005.

|Year  |   | Long-Term Debt |  |  |   | Lease Obligation |  |  |   | Total Cash Obligation | 
|----- | - | -------------- |  |  | - | ---------------- |  |  | - | --------------------- | 
|2006  | $ | -              |  |  | $ | 30,000           |  |  | $ | 30,000                | 
|2007  |   | 400,000        |  |  |   | -                |  |  | $ | 400,000               | 
|2008  |   | -              |  |  |   | -                |  |  | $ | -                     | 
|      |   |                |  |  |   |                  |  |  |   |                       | 
|Total | $ | 400,000        |  |  | $ | 30,000           |  |  | $ | 430,000               | 
|      |   |                |  |  |   |                  |  |  |   |                       | 

# Off-Balance Sheet
Financing Arrangements

As
of December 31, 2005 we had no off-balance sheet financing arrangements.

# New Accounting Policies

Effective
January 1, 2003, we adopted the provisions of SFAS No. 143, Accounting for Asset
Retirement Obligations. This statement generally applies to legal obligations
associated with the retirement of long-lived assets that result from the acquisition,
construction, development and/or the normal operation of a long-lived asset. SFAS No. 143
requires us to recognize the fair value of asset retirement obligations in our financial
statements by capitalizing that cost as a part of the cost of the related asset. In
regards to us, this statement applies directly to the plug and abandonment liabilities
associated with our net working interest in well bores. The additional carrying amount is
depleted over the estimated lives of the properties. The discounted liability is based on
historical abandonment costs in specific areas and is accreted at the end of each
accounting period through charges to accretion expense. The liability is discounted using
a credit-adjusted risk-free rate of approximately 8.08%. If the obligation is settled for
other than the carrying amount, a gain or loss is recognized on settlement. Upon adoption
of SFAS No. 143, we recorded an increase to our discounted abandonment liability of
$236,718, increased property and equipment cost by $217,878 and recognized a one-time
cumulative effect charge of $11,813 (net of a deferred tax benefit of $7,027).

The
adoption of SFAS No. 143 also affected the depreciation, depletion and amortization on an
on-going basis. The additionally capitalized amount for the discounted abandonment
liability increases the base amount used in calculating depletion. This effect was an
increase in depreciation, depletion and amortization for the years ended December 31,
2003, 2004 and 2005 of $7,459, $10,798 and $21,619, respectively. The adoption of SFAS No.
143 also impacted the way the ceiling test is calculated under the full cost accounting
method used by the Company, in that an estimation of future abandonment costs are now
excluded from the computation of the present value of estimated future net revenues for
purposes of the full cost ceiling calculation. However, these costs are now part of the
base amount, so while the way the calculation is performed has changed, the end result
remains the same. There were no other impacts of the adoption of SFAS No. 143.

In
January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest
Entities. This interpretation establishes the requirement for a primary beneficiary to
consolidate certain entities in which equity investors do not have the characteristics of
a controlling financial interest or do not have sufficient equity at risk for the entity
to finance its activities without additional subordinated financial support from other
parties. We do not have an interest in a variable interest entity and the adoption of the
statement did not have an impact on our financial statements.

---



In
May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments
with Characteristics of both Liabilities and Equity. This statement was effective for
us in July 2003. The statement requires financial instruments to be classified as
liabilities if the financial instruments are issued in the form of shares that are
mandatorily redeemable or embody an obligation to repurchase equity shares. We issued a
put option in exchange for oil and gas property interests in December 2004. The put option
was originally classified as a liability; therefore, the adoption of the statement did not
have an impact on our financial statements.

# 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 2004, we did experience continued increases in cost during 2005 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 2005 as oil and gas prices rose
significantly. Costs for oilfield services and materials increased during 2005 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 50.

|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, 2005, 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, 2005, our internal control over financial
reporting is effective based on those criteria.

Hansen,
Barnett & Maxwell, 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 15, 2006

---



| | /s/ Lloyd T. RochfordChief Executive Officer
| | --------------------------------------------

| | /s/ William R. BroaddrickChief Financial Officer
| | ------------------------------------------------

# 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, 2005, 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, 2005 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, 2005, 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, 2005 and
2004, and the related consolidated statements of operations, stockholders equity and
cash flows for each of the three years in the period ended December 31, 2005 of Arena
Resources, Inc. and our report dated March 14, 2006 expressed an unqualified opinion
thereon.

| | HANSEN, BARNETT &
MAXWELL
| | -------------------------

Salt Lake City, Utah
March 14, 2006

Changes in Internal Control Over
Financial Reporting.

We
made no change in our internal control over financial reporting during our fourth quarter
of 2005 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 and
Executive Officers
|-------- |  | --------------------------------

# Executive Officers and Directors

The
following table sets forth information regarding our executive officers, certain other
officers and directors as of December 31, 2005:

|Name                  | Age | Position                                                   
|--------------------- | --- | -----------------------------------------------------------
|Lloyd T. Rochford     | 59  | President and Chief Executive Officer and Director         
|Stanley M. McCabe     | 73  | Chairman of the Board of Directors, Secretary and Treasurer
|William R. Broaddrick | 28  | Vice President and Chief Financial Officer                 
|Charles M. Crawford   | 53  | Director                                                   
|Chris V. Kemendo, Jr. | 84  | Director                                                   
|Clayton E. Woodrum    | 65  | 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
2005.

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, 59, 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, 73, 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, 28, 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, 53, 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, 84, has from 1989 to present acted as an independent financial business
          and accounting consultant to various clients. Mr. Kemendo has 56 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, 65, 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
2006 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.

# Board Committees

Our
board of directors has established an audit committee, whose 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. The audit committee is comprised of two
independent directors, consisting of Messrs. Kemendo and Woodrum, with Mr. Woodrum acting
as the chairman. Our board of directors has determined that each member of the audit
committee qualifies as an 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 and
Woodrum further qualifies as independent in accordance with the applicable
regulations adopted by the SEC and American Stock Exchange.

Our
board of directors has established a compensation committee, whose principal function is
to make recommendations regarding the compensation of the Companys officers. In
accordance with the rules of the American 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. The compensation committee is comprised of two independent directors,
consisting of Messrs. Kemendo and Woodrum, with Mr. Woodrum acting as the chairman.
Compensation for all other officers is also recommended to the Board for determination, by
the compensation committee.

We
currently do not have a nominating committee. Instead, in accordance with the rules of the
American Stock Exchange, the independent directors (currently, Messrs. Crawford, Kemendo
and Woodrum) fulfill the role of a nominating committee. Since our inception in 2000, we
have had only six directors, five of whom continue to serve at this time. On the only
occasion when a vacancy occurred (following a resignation), the new director was
unanimously approved by the remaining directors. Therefore, the Board has not felt it
necessary to have a standing nominating committee to deal with its infrequent changes in
membership. If and when future vacancies occur, the Board would consider director nominees
recommended by shareholders, as well as director nominees recommended by a majority of the
directors who are then independent. The board does not have a formal policy regarding the
consideration of, procedures to be followed by, minimum requirements of or process for
identifying or evaluation nominees recommended by security holders.

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

# Director Compensation

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

---



# Compensation Committee
Interlocks and Insider Participation

None
of our executive officers serve as a member of the board of directors or compensation
committee of any entity that has one or more of its executive officers serving as a member
of our board of directors or compensation committee.

# 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.

# 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.

|Item 11: |  | Executive
Compensation
|-------- |  | ----------------------

The
following table sets forth information concerning the compensation paid by us for the
three most recent fiscal years to our chief executive officer and our other two executive
officers.

Summary Compensation
Table

|                                                             |      | Annual Compensation | Long-Term Compensation Awards
|------------------------------------------------------------ | ---- | ------------------- | -----------------------------
|                                                             |      |                     |                              
|Name and Principal Position                                  | Year | Salary(1)           | Bonus                        
|                                                             |      |                     |                              
|Lloyd T. RochfordPresident and Chief Executive Officer       | 2003 | $ 36,000            | $            -               
|                                                             | 2004 | $ 36,000            | $            -               
|                                                             | 2005 | $ 36,000            | $            -               
|                                                             |      |                     |                              
|Stanley M. McCabeChairman of the Board                       | 2003 | $ 36,000            | $            -               
|                                                             | 2004 | $ 36,000            | $            -               
|                                                             | 2004 | $ 36,000            | $            -               
|                                                             |      |                     |                              
|William R. BroaddrickVice President, Chief Financial Officer | 2003 | $ 47,927            | $            -               
|                                                             | 2004 | $ 51,500            | $    4,167                   
|                                                             | 2004 | $ 55,667            | $    2,458                   

(1) Mr.
Broaddricks salary reflects raises that occurred in mid-year           to increase
his annual salary to $50,000 during 2003, $54,000 during 2004 and           $59,000
during 2005. There are no current plans to change any officers          salary from
their level at December 31, 2005.(2) The
fair value of           the options issued in 2003 was estimated on the dates granted
using the           Black-Scholes option pricing model with the following weighted
average           assumptions: dividend yield of 0%; expected volatility of 36.2%;
risk-free           interest rate of 2.9% and expected lives of 5.0 years. The weighted
average           remaining contractual life of the options issued in 2003 at December
31, 2005           was 2.3 years. The fair value of the options issued in 2005 was
estimated on the           dates granted using the Black-Scholes option pricing model
with the following           weighted average assumptions: dividend yield of 0%; expected
volatility of           32.3%; risk-free interest rate of 3.7% and expected lives of 5.0
years. The           weighted average remaining contractual life of the options issued in
2005 at           December 31, 2005 was 4.0 years.

---



# Employee Benefit Plans

Equity
Incentive Plan. 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 further amended by our shareholders at our annual meetings in December 2004
and 2005. The executive stock option plan is intended to promote continuity of management
and to provide increased incentive and personal interest in our welfare by those key
employees who are primarily responsible for shaping and carrying out our long-range plans
and securing our continued growth and financial success. In addition, by encouraging stock
ownership by directors who are not our employees, the executive stock option plan is
intended to attract and retain qualified directors.

The
plan is administered by Messrs. Rochford and McCabe, and they have the authority to select
the key employees and non-employee directors to be participants in the plan, to determine
the awards to be granted to participants and the number of shares covered by such awards,
to set the terms and conditions of such awards and to establish, amend or waive rules for
the administration of the plan.

Any
of our key employees, including any of our executive officers or directors, is eligible to
be granted awards by plan administrators. The plan authorizes the grant of stock options
to key employees, all of which have been non-qualified stock options. Our non-employee
directors are only eligible to be granted non-qualified stock options under the plan.

The
plan provides that up to a total of 2,000,000 shares of common stock, subject to
adjustment to reflect stock dividends and other capital changes, are available for
granting of awards under the executive stock option plan. 1,475,000 of the shares
available for grant under the plan have been reserved for issuance pursuant to options
granted during 2003 and 2005.

The
following table provides information regarding option exercises and fiscal year-end option
values calculated by determining the difference between the closing price of our common
stock at December 31, 2005 and the exercise price of the options.

---



|                      | SharesAcquiredonExercise | ValueRealized($) | Number of UnexercisedSecurities UnderlyingOptions/SARs at FY-End(#)Exercisable/Unexercisable | Value of UnexercisableIn-The-MoneyOptions/SARs at FY-End($) Exercisable/Unexercisable
|--------------------- | ------------------------ | ---------------- | -------------------------------------------------------------------------------------------- | -------------------------------------------------------------------------------------
|                      |                          |                  |                                                                                              |                                                                                      
|Lloyd T. Rochford     | 0                        | 0                | 50,000/200,000                                                                               | $1,195,000/$4,780,000                                                                
|Stanley M. McCabe     | 0                        | 0                | 50,000/200,000                                                                               | $1,195,000/$4,780,000                                                                
|William R. Broaddrick | 0                        | 0                | 100,000/150,000                                                                              | $2,390,000/$3,585,000                                                                
|Phillip W. Terry      | 0                        | 0                | 100,000/150,000                                                                              | $2,390,000/$3,585,000                                                                
|Raymond H. Estep      | 0                        | 0                | 40,000/60,000                                                                                | $956,000/$1,434,000                                                                  
|Clayton E. Woodrum    | 0                        | 0                | 20,000/42,500                                                                                | $456,000/$969,000                                                                    
|Charles M. Crawford   | 0                        | 0                | 20,000/42,500                                                                                | $478,000/$1,017,750                                                                  
|Chris V. Kemendo, Jr. | 0                        | 0                | 20,000/55,000                                                                                | $478,000/$1,314,500                                                                  
|Danny Palmer          | 0                        | 0                | 0/50,000                                                                                     | $0/$965,000                                                                          
|Stephanie Mefford     | 0                        | 0                | 0/25,000                                                                                     | $0/$482,500                                                                          
|Kim Nichols           | 0                        | 0                | 0/50,000                                                                                     | 0/$337,500                                                                           

The following table sets forth
information concerning our executive stock option plan as of December 31, 2005.

|                                                         | Number ofsecurities to beissued uponexercise ofoutstandingoptions | Weighted-averageexercise priceof outstandingoptions | Number of securitiesremaining available forfuture issuance undercompensation plans(excluding securities incolumn (a))
|-------------------------------------------------------- | ----------------------------------------------------------------- | --------------------------------------------------- | ---------------------------------------------------------------------------------------------------------------------
|                                                         |                                                                   |                                                     |                                                                                                                      
|                                                         | (a)                                                               | (b)                                                 | (c)                                                                                                                  
|Equity compensationplans approved bysecurity holders     | 1,425,000                                                         | 5.55                                                | 575,000                                                                                                              
|                                                         |                                                                   |                                                     |                                                                                                                      
|Equity compensationplans not approved bysecurity holders | -                                                                 | -                                                   | -                                                                                                                    
|                                                         |                                                                   |                                                     |                                                                                                                      
|Total                                                    | 1,425,000                                                         | 5.55                                                | 575,000                                                                                                              
|                                                         |                                                                   |                                                     |                                                                                                                      

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

The
following table sets forth, as February 28, 2006, 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
|------------------------------------ |  | -----------------------------------------
|                                     | 
|
|                                     |  |                                          
|Lloyd T. Rochford                    |  | 1,212,600 (1)                            
|Stanley M. McCabe                    |  | 1,213,000 (2)                            
|William R. Broaddrick                |  | 154,500 (3)                              
|Charles M. Crawford                  |  | 32,500 (4)                               
|Chris V. Kemendo, Jr                 |  | 35,100 (5)                               
|Clayton E. Woodrum                   |  | 22,500 (6)                               
|                                     |  |                                          
|All directors and executive officers |  | 2,670,200 (7)                            
|                                     |  |                                          

|(1) |  | 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.
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) |  | 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.
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) |  | Includes
100,000 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
20,000 shares issuable upon the exercise of stock options that are           currently
exercisable and 12,500 shares issuable upon the exercise of stock           options that
are exercisable within 60 days.
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(5) |  | Includes
20,000 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
20,000 shares issuable upon the exercise of stock options that are           currently
exercisable and 2,500 shares issuable upon exercise of stock options           that are
exercisable within 60 days..
|--- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(7) |  | Includes
260,000 shares issuable upon the exercise of stock options that are           currently
exercisable and 120,000 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 13,226,702 shares of
our common stock outstanding as of February 28, 2006.

|Item 13: |  | Certain
Relationships and Related Transactions
|-------- |  | ----------------------------------------------

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, 2007. 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).

|Item 14: |  | Principal
Accountant Fees and Services
|-------- |  | --------------------------------------

The
firm of Hansen, Barnett & Maxwell, (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, 2005, and the Audit
Committee has selected HBM to serve in the same capacity for the fiscal year ending
December 31, 2006. 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 $75,000 and $60,548 for professional
services rendered for the audit of the Companys financial statements for the years
ended December 31, 2005 and 2004, respectively, and its reviews of the Companys
financial statements included in its Form 10-QSBs for the first three quarters of
2005, 2004.

Audit
Related Fees. HBM billed the Company $5,500 and $78,998 for the years ended December
31, 2005 and 2004, respectively, for its services in connection with the review of the
Companys registration statement on Form S-3 (which was filed with the SEC in 2005),
the review of the Companys registration statement on Form SB-2 (which was filed with
the SEC in 2004) and for the audit of the Fuhrman-Mascho property acquisition, and which
are not included in the audit fees identified above.

Tax
Fees. HBM billed the Company an aggregate of $5,000 and $3,000 for professional
services rendered for tax compliance, tax advice and tax planning for the years ended
December 31, 2005 and 2004.

All
Other Fees.  No other fees were billed by HBM to the Company during 2005 and 2004.

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 13: |  | 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)
|---- |  | -------------------------------------------------------------------------

|23.1 |  | Consent
of Lee Keeling and Associates, Inc., Independent Petroleum Engineers
|---- |  | ----------------------------------------------------------------------------

---



|23.2 |  | Consent
of Hansen, Barnett & Maxwell, 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:                  
| |                      
| |                      
| |                      
| |                      
| | Date: March 15, 2006 
| |                      
| | By:                  
| |                      
| |                      
| |                      
| |                      
| | Date: March 15, 2006 
| |                      
| | By:                  
| |                      
| |                      
| |                      
| |                      
| | Date: March 15, 2006 

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.

| | By:                  | /s/  Lloyd T. Rochford
| | -------------------- | ----------------------
| |                      |                       
| |                      | Mr. Lloyd T. Rochford 
| |                      | Director              
| |                      |                       
| | Date: March 15, 2006
| |                      |                       
| | By:                  | /s/ Stanley McCabe    
| |                      |                       
| |                      | Mr. Stanley McCabe    
| |                      | Director              
| |                      |                       
| | Date: March 15, 2006
| |                      |                       
| | By:                  | /s/  Charles Crawford 
| |                      |                       
| |                      | Mr. Charles Crawford  
| |                      | Director              
| |                      |                       
| | Date: March 15, 2006

---



| | By:                  | /s/  Chris V. Kemendo, Jr.
| | -------------------- | --------------------------
| |                      |                           
| |                      | Mr. Chris V. Kemendo, Jr. 
| |                      | Director                  
| |                      |                           
| | Date: March 15, 2006
| |                      |                           
| | By:                  | /s/  Clayton E. Woodrum   
| |                      |                           
| |                      | Mr. Clayton E. Woodrum    
| |                      | Director                  
| |                      |                           
| | Date: March 15, 2006

---



# ARENA RESOURCES, INC.

# INDEX TO FINANCIAL
STATEMENTS

|                                                             | Page
|------------------------------------------------------------ | ----
|Report of Independent Registered Public Accounting Firm      | 53  
|Balance Sheets                                               | 54  
|Statements of Operations                                     | 55  
|Statements of Stockholders' Equity                           | 56  
|Statements of Cash Flows                                     | 57  
|Notes to Financial Statements                                | 59  
|Supplemental Information on Oil and Gas Producing Activities | 73  

---



|HANSEN, BARNETT & MAXWELL     |                                   
|----------------------------- | ----------------------------------
|A Professional Corporation    |                                   
|CERTIFIED PUBLIC ACCOUNTANTS  | Registered with the Public Company
|AND                           | Accounting Oversight Board        
|BUSINESS CONSULTANTS          |                                   
|5 Triad Center, Suite 750     |                                   
|Salt Lake City, UT 84180-1128 | BAKER TILLY                       
|Phone: (801) 532-2200         | INTERNATIONAL                     
|Fax: (801) 532-7944           |                                   
|www.hbmcpas.com               |                                   

# REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM

To
the Board of Directors and Stockholders
of Arena Resources, Inc.

We have audited the accompanying
balance sheets of Arena Resources, Inc. as of December 31, 2005 and 2004, and the related
statements of operations, stockholders equity, and cash flows for each of the three
years in the period ended December 31, 2005. 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 audits 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 that 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 financial
position of Arena Resources, Inc. as of December 31, 2005 and 2004, and the results of its
operations and its cash flows for each of the three years in the period ended December 31,
2005 in conformity with accounting principles generally accepted in the United States of
America.

As discussed in Note 5 to the
financial statements, the Company changed its method of recognizing asset retirement
obligations in 2003.

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, 2005, 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 14, 2006 expressed an unqualified opinion
thereon.

| | HANSEN, BARNETT &
MAXWELL
| | -------------------------

Salt Lake City, Utah
March 14, 2006

---



ARENA RESOURCES, INC.
BALANCE SHEETS

|December 31,                                                                                                                         |   | 2005        |  |   | 2004       
|------------------------------------------------------------------------------------------------------------------------------------ | - | ----------- |  | - | -----------
|                                                                                                                                    
|ASSETS                                                                                                                               |   |             |  |   |            
|Current Assets                                                                                                                       |   |             |  |   |            
|Cash                                                                                                                                 | $ | 4,317,114   |  | $ | 1,253,969  
|Account receivable                                                                                                                   |   | 3,180,749   |  |   | 1,149,513  
|Joint interest billing receivable                                                                                                    |   | 140,561     |  |   | 61,805     
|Prepaid expenses                                                                                                                     |   | 35,436      |  |   | 33,136     
|                                                                                                                                    
|Total Current Assets                                                                                                                 |   | 7,673,860   |  |   | 2,498,423  
|                                                                                                                                    
|Property and Equipment, Using Full Cost Accounting                                                                                   |   |             |  |   |            
|Oil and gas properties subject to amortization                                                                                       |   | 69,770,685  |  |   | 34,457,137 
|Drilling advances                                                                                                                    |   | -           |  |   | 900,000    
|Equipment                                                                                                                            |   | 26,687      |  |   | 26,687     
|Deposits on drilling rig                                                                                                             |   | 1,191,126   |  |   | -          
|Office equipment                                                                                                                     |   | 106,177     |  |   | 60,401     
|                                                                                                                                    
|Total Property and Equipment                                                                                                         |   | 71,094,675  |  |   | 35,444,225 
|Less:  Accumulated depreciation and amortization                                                                                     |   | (4,346,628) |  |   | (1,565,124)
|                                                                                                                                    
|Net Property and Equipment                                                                                                           |   | 66,748,047  |  |   | 33,879,101 
|                                                                                                                                    
|Total Assets                                                                                                                         | $ | 74,421,907  |  | $ | 36,377,524 
|                                                                                                                                    
|                                                                                                                                     |   |             |  |   |            
|LIABILITIES AND STOCKHOLDERS' EQUITY                                                                                                 |   |             |  |   |            
|Current Liabilities                                                                                                                  |   |             |  |   |            
|Accounts payable                                                                                                                     | $ | 6,038,691   |  | $ | 1,805,865  
|Income taxes payable                                                                                                                 |   | 329,986     |  |   | -          
|Accrued liabilities                                                                                                                  |   | 221,519     |  |   | 34,800     
|                                                                                                                                    
|Total Current Liabilities                                                                                                            |   | 6,590,196   |  |   | 1,840,665  
|                                                                                                                                    
|Long-Term Liabilities                                                                                                                |   |             |  |   |            
|Notes payable                                                                                                                        |   | -           |  |   | 10,000,000 
|Notes payable to related parties                                                                                                     |   | 400,000     |  |   | 400,000    
|Put option                                                                                                                           |   | -           |  |   | 95,033     
|Asset retirement liability                                                                                                           |   | 1,515,347   |  |   | 1,267,993  
|Deferred income taxes                                                                                                                |   | 7,187,609   |  |   | 1,971,990  
|                                                                                                                                    
|Total Long-Term Liabilities                                                                                                          |   | 9,102,956   |  |   | 13,735,016 
|                                                                                                                                    
|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;    
13,099,702 shares and 9,132,910 shares outstanding, respectively |   | 13,100      |  |   | 9,133      
|Additional paid-in capital                                                                                                           |   | 45,331,234  |  |   | 15,258,352 
|Options and warrants outstanding                                                                                                     |   | 1,483,807   |  |   | 3,213,159  
|Deferred compensation                                                                                                                |   | (115,545)   |  |   | (234,277)  
|Retained earnings                                                                                                                    |   | 12,016,159  |  |   | 2,555,476  
|                                                                                                                                    
|Total Stockholders' Equity                                                                                                           |   | 58,728,755  |  |   | 20,801,843 
|                                                                                                                                    
|Total Liabilities and Stockholders' Equity                                                                                           | $ | 74,421,907  |  | $ | 36,377,524 
|                                                                                                                                    

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

---



ARENA RESOURCES, INC.
STATEMENTS OF OPERATIONS

|For the Years Ended December 31,                           |   | 2005        |  |   | 2004        |  |   | 2003     
|---------------------------------------------------------- | - | ----------- |  | - | ----------- |  | - | ---------
|                                                          
|Oil and Gas Revenues                                       | $ | 25,843,077  |  | $ | 8,482,130   |  | $ | 3,665,477
|                                                          
|Costs and Operating Expenses                               |   |             |  |   |             |  |   |          
|Oil and gas production costs                               |   | 3,832,486   |  |   | 1,975,835   |  |   | 1,149,136
|Oil and gas production taxes                               |   | 1,939,739   |  |   | 629,703     |  |   | 269,563  
|Depreciation, depletion and amortization                   |   | 2,781,504   |  |   | 1,011,602   |  |   | 360,282  
|Accretion expense                                          |   | 102,585     |  |   | 53,729      |  |   | 32,212   
|General and administrative expense                         |   | 1,365,590   |  |   | 874,850     |  |   | 778,774  
|                                                          
|Total Costs and Operating Expenses                         |   | 10,021,904  |  |   | 4,545,719   |  |   | 2,589,967
|                                                          
|Other Income (Expense)                                     |   |             |  |   |             |  |   |          
|Gain from change in fair value of put options              |   | 95,033      |  |   | 68,251      |  |   | 47,699   
|Other financing expense                                    |   | (597,773)   |  |   | -           |  |   | -        
|Interest expense                                           |   | (229,624)   |  |   | (155,936)   |  |   | (38,798) 
|                                                          
|Net Other Income (Expense)                                 |   | (732,364)   |  |   | (87,685)    |  |   | (8,901)  
|                                                          
|Income Before Provision for Income Taxes and Cumulative    |   |             |  |   |             |  |   |          
|Effect of  Change in Accounting Principle                  |   | 15,088,809  |  |   | 3,848,726   |  |   | 1,084,411
|                                                           |   |             |  |   |             |  |   |          
|Provision for Deferred Income Taxes                        |   | (5,628,126) |  |   | (1,397,074) |  |   | (402,455)
|                                                          
|Income Before Cumulative Effect of Change                  |   |             |  |   |             |  |   |          
|in Accounting Principle                                    |   | 9,460,683   |  |   | 2,451,652   |  |   | 681,956  
|                                                           |   |             |  |   |             |  |   |          
|Cumulative Effect of Change in Accounting Principle        |   | -           |  |   | -           |  |   | (11,813) 
|                                                          
|Net Income                                                 | $ | 9,460,683   |  | $ | 2,451,652   |  | $ | 670,143  
|                                                          
|Basic Earnings Per Share                                   |   |             |  |   |             |  |   |          
|Before cumulative effect of change in accounting principle | $ | 0.85        |  | $ | 0.31        |  | $ | 0.10     
|Net Income                                                 |   | 0.85        |  |   | 0.31        |  |   | 0.10     
|Diluted Earnings Per Share                                 |   |             |  |   |             |  |   |          
|Before cumulative effect of change in accounting principle | $ | 0.75        |  | $ | 0.28        |  | $ | 0.09     
|Net Income                                                 |   | 0.75        |  |   | 0.28        |  |   | 0.09     
|                                                          

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

---



ARENA RESOURCES, INC.
STATEMENTS OF STOCKHOLDERS EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2003, 2004 AND 2005

|                                                | Common Stock |   |            |   |                |   |                     |   |                      |   |                 
|----------------------------------------------- | ------------ | - | ---------- | - | -------------- | - | ------------------- | - | -------------------- | - | ----------------
|                                                |              |   | Additional |   | Options and    |   |                     |   |                      |   | Total           
|                                                | Shares       |   | Amount     |   | Paid-InCapital |   | WarrantsOutstanding |   | DeferredCompensation |   | RetainedEarnings
|                                               
|Balance December 31, 2002                       | 6,282,056    | $ | 6,282      | $ | 5,287,189      | $ | 382,040             | $ | -                    | $ | (566,319)       
|Issuance for cash, net                          | 790,294      |   | 790        |   | 1,274,256      |   | 436,154             |   | -                    |   | -               
|Issuance of employee stock options              | -            |   | -          |   | -              |   | 660,000             |   | (660,000)            |   | -               
|Issuance of warrants as consulting fee          |              |   |            |   |                |   |                     |   |                      |   |                 
|for 2002 offering                               | -            |   | -          |   | (15,922)       |   | 15,922              |   | -                    |   | -               
|Cancellation of shares for extension            |              |   |            |   |                |   |                     |   |                      |   |                 
|of lock up                                      | (500)        |   | -          |   | -              |   | -                   |   | -                    |   | -               
|Issuance of common stock for services           | 13,847       |   | 14         |   | 75,026         |   | -                   |   | -                    |   | -               
|Warrants exercised                              | 19,400       |   | 19         |   | 54,883         |   | (20,952)            |   | -                    |   | -               
|Issuance of common stock                        |              |   |            |   |                |   |                     |   |                      |   |                 
|in property acquisitions                        | 57,000       |   | 57         |   | 319,493        |   | -                   |   | -                    |   | -               
|Amortization of deferred compensation           | -            |   | -          |   | -              |   | -                   |   | 221,198              |   | -               
|Net income                                      | -            |   | -          |   | -              |   | -                   |   | -                    |   | 670,143         
|                                               
|Balance December 31, 2003                       | 7,162,097    |   | 7,162      |   | 6,994,925      |   | 1,473,164           |   | (438,802)            |   | 103,824         
|Warrants exercised                              | 78,300       |   | 78         |   | 395,843        |   | (41,796)            |   | -                    |   | -               
|Issuance for cash, net                          | 1,667,500    |   | 1,668      |   | 6,469,225      |   | 1,781,791           |   | -                    |   | -               
|Issuance of common stock in property            |              |   |            |   |                |   |                     |   |                      |   |                 
|acquisitions, net of call option
      received | 225,013      |   | 225        |   | 1,398,359      |   | -                   |   | -                    |   | -               
|Amortization of deferred compensation           | -            |   | -          |   | -              |   | -                   |   | 204,525              |   | -               
|Net income                                      | -            |   | -          |   | -              |   | -                   |   | -                    |   | 2,451,652       
|                                               
|Balance December 31, 2004                       | 9,132,910    |   | 9,133      |   | 15,258,352     |   | 3,213,159           |   | (234,277)            |   | 2,555,476       
|Warrants exercised for cash, net                | 2,971,273    |   | 2,971      |   | 20,194,042     |   | (2,322,392)         |   | -                    |   | -               
|Expiration of warrants                          | -            |   | -          |   | 4,733          |   | (4,733)             |   | -                    |   | -               
|Issuance of common stock in                     |              |   |            |   |                |   |                     |   |                      |   |                 
|property acquisition                            | 25,000       |   | 25         |   | 340,625        |   | -                   |   | -                    |   | -               
|Issuance for cash, net                          | 970,874      |   | 971        |   | 9,535,967      |   | -                   |   | -                    |   | -               
|Issuance of warrants for services               |              |   |            |   |                |   |                     |   |                      |   |                 
|relating to private offering                    | -            |   | -          |   | -              |   | 597,773             |   | -                    |   | -               
|Cancellation of stock issued in                 |              |   |            |   |                |   |                     |   |                      |   |                 
|property acquisition                            | (355)        |   | -          |   | (2,485)        |   | -                   |   | -                    |   | -               
|Amortization of deferred compensation           | -            |   | -          |   | -              |   | -                   |   | 118,732              |   | -               
|Net income                                      | -            |   | -          |   | -              |   | -                   |   | -                    |   | 9,460,683       
|                                               
|Balance December 31, 2005                       | 13,099,702   | $ | 13,100     | $ | 45,331,234     | $ | 1,483,807           | $ | (115,545)            | $ | 12,016,159      
|                                               

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

---



ARENA RESOURCES, INC.
STATEMENTS OF CASH FLOWS

|For the Years Ended December 31                                                         |   | 2005         |  |   | 2004         |  |   | 2003       
|--------------------------------------------------------------------------------------- | - | ------------ |  | - | ------------ |  | - | -----------
|                                                                                       
|Cash Flows From Operating Activities                                                    |   |              |  |   |              |  |   |            
|Net income                                                                              | $ | 9,460,683    |  | $ | 2,451,652    |  | $ | 670,143    
|Adjustments to reconcile net income to net cash       provided by operating activities: |   |              |  |   |              |  |   |            
|Shares issued for services                                                              |   | -            |  |   | -            |  |   | 75,040     
|Warrants issued for financing expense                                                   |   | 597,773      |  |   | -            |  |   | -          
|Depreciation, depletion and amortization                                                |   | 2,781,504    |  |   | 1,011,602    |  |   | 360,282    
|Provision for income taxes                                                              |   | 5,628,126    |  |   | 1,397,074    |  |   | 402,455    
|Gain from change in fair value of put option                                            |   | (95,033)     |  |   | (68,251)     |  |   | (47,699)   
|Cumulative effect of change in accounting principle                                     |   | -            |  |   | -            |  |   | 11,813     
|Loss on sale of equipment                                                               |   | -            |  |   | 5,586        |  |   | -          
|Amortization of deferred compensation                                                   |   | 118,732      |  |   | 204,525      |  |   | 221,198    
|Accretion of discounted liabilities                                                     |   | 102,585      |  |   | 83,730       |  |   | 32,212     
|Changes in assets and liabilities:                                                      |   |              |  |   |              |  |   |            
|Accounts and joint interest receivable                                                  |   | (2,109,992)  |  |   | (656,864)    |  |   | (119,474)  
|Other changes in deferred income taxes                                                  |   | (82,521)     |  |   | -            |  |   | -          
|Prepaid expenses                                                                        |   | (2,300)      |  |   | (4,201)      |  |   | (27,807)   
|Accounts payable and accrued liabilities                                                |   | 4,419,545    |  |   | 1,570,831    |  |   | 74,787     
|                                                                                       
|Net Cash Provided by Operating Activities                                               |   | 20,819,102   |  |   | 5,995,684    |  |   | 1,652,950  
|                                                                                       
|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 Furhman-Mascho properties                                  |   | -            |  |   | (711,802)    |  |   | -          
|Purchase and development of oil and gas properties                                      |   | (34,665,614) |  |   | (4,802,141)  |  |   | (3,050,558)
|Maturity of long-term investment                                                        |   | -            |  |   | 25,234       |  |   | 51,268     
|Purchase of machinery and office equipment                                              |   | (1,236,902)  |  |   | (41,423)     |  |   | (30,992)   
|                                                                                       
|Net Cash Used in Investing Activities                                                   |   | (35,167,516) |  |   | (6,547,632)  |  |   | (3,030,282)
|                                                                                       
|Cash Flows From Financing Activities                                                    |   |              |  |   |              |  |   |            
|Proceeds from issuance of common stock and warrants,       net of offering costs        |   | 9,536,938    |  |   | 8,383,557    |  |   | 1,580,328  
|Proceeds from exercise of warrants, net of offering costs                               |   | 17,874,621   |  |   | 354,124      |  |   | 33,950     
|Issuance of note payable                                                                |   | -            |  |   | 2,000,000    |  |   | -          
|Payment of notes payable                                                                |   | (10,000,000) |  |   | (10,008,440) |  |   | -          
|Collection of common stock subscription receivable                                      |   | -            |  |   | -            |  |   | 157,500    
|Payment of accrued dividends to preferred stockholders                                  |   | -            |  |   | -            |  |   | (114,685)  
|                                                                                       
|Net Cash Provided by Financing Activities                                               |   | 17,411,559   |  |   | 729,241      |  |   | 1,657,093  
|                                                                                       
|Net Increase in Cash                                                                    |   | 3,063,145    |  |   | 177,293      |  |   | 279,761    
|                                                                                        |   |              |  |   |              |  |   |            
|Cash at Beginning of Period                                                             |   | 1,253,969    |  |   | 1,076,676    |  |   | 796,915    
|                                                                                       
|Cash at End of Period                                                                   | $ | 4,317,114    |  | $ | 1,253,969    |  | $ | 1,076,676  
|                                                                                       

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                                                    |   | 2005    |  |   | 2004        |  |   | 2003   
|---------------------------------------------------------------------------------- | - | ------- |  | - | ----------- |  | - | -------
|                                                                                  
|Supplemental Cash Flow Information                                                 |   |         |  |   |             |  |   |        
|Cash paid for income taxes                                                         | $ | 82,521  |  | $ | -           |  | $ | -      
|Cash paid for interest                                                             | $ | 199,624 |  | $ | 158,950     |  | $ | 38,798 
|                                                                                  
|Non-Cash Investing and Financing Activities                                        |   |         |  |   |             |  |   |        
|Common stock issued for properties                                                 | $ | 340,650 |  | $ | 34,500      |  | $ | 319,550
|Asset retirement obligation incurred in property       acquisition and development |   | 144,769 |  |   | 570,029     |  |   | 338,271
|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 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.

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.

Cash  The
Company had deposits with a bank that are $4,217,114 in excess of federally insured limits
at December 31, 2005.

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.

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, 2005, 2004 and
2003.

|                                                   | For the Years Ended December 31,
|-------------------------------------------------- | --------------------------------
|                                                   |                                 
|                                                   |                                 
|Depletion                                          | $                               
|Depletion rate, per barrel-of-oil-equivalent (BOE) | $                               

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: 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;
plus the cost of properties not being amortized; plus the lower of cost or estimated fair
value of unproven properties included in the costs being amortized; less income tax
effects related to differences between the book and tax basis of the properties.

---



# ARENA RESOURCES, INC.NOTES TO FINANCIAL
STATEMENTS

Support and Office
Equipment  Depreciation of support and office equipment is computed
using the straight-line method over the estimated useful lifes of the assets which are
currently five to seven years. Depreciation expense was $22,659, $13,908 and $9,950 for
the years ended December 31, 2005, 2004 and 2003, respectively.

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 receivable, notes payable, and long-term debt
approximate fair value because the underlying instruments are at interest rates which
approximate current market rates.

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.

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 is calculated to give effect to potentially issuable dilutive common shares.

Major Customers
 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.
During the year ended December 31, 2003, sales to three customers represented 51%, 19% and
11% of total sales, respectively. At December 31, 2003, these three customers made up 46%,
16% and 17% of accounts receivable, respectively.

Stock-Based Employee
Compensation  In 2003 and 2005, the Company issued stock options to
directors and employees, which are described more fully in Note 7. The Company applies the
recognition and measurement principles of Accounting Principles Board Opinion No. 25,
Accounting for Stock Issued to Employees (APB 25) and related interpretations in
accounting for its stock-based compensation awards to employees. The Company recognized
compensation expense relating to those stock options of $118,732, $204,525 and $221,198
for the years ended December 31, 2005, 2004 and 2003, respectively.

Alternately, Statement of Financial
Accounting Standards (SFAS) No. 123, Accounting for Stock-Based Compensation (SFAS
No. 123), allows companies to recognize compensation expense over the related service
period based on the grant date fair value of the stock option awards. The following table
illustrates the effect on net income and basic and diluted earnings per share if the
Company had applied the fair value recognition provisions of SFAS No. 123 to stock-based
employee compensation:

---



# ARENA RESOURCES, INC.NOTES TO FINANCIAL
STATEMENTS

|For the Years Ended December 31,                                                                |   | 2005      |  |   | 2004      |  |   | 2003     
|----------------------------------------------------------------------------------------------- | - | --------- |  | - | --------- |  | - | ---------
|                                                                                               
|Net income, as reported                                                                         | $ | 9,460,683 |  | $ | 2,451,652 |  | $ | 670,143  
|Add: Stock based employee compensation expense included                                         |   |           |  |   |           |  |   |          
|in net income, net of related tax effects                                                       |   | 74,444    |  |   | 128,365   |  |   | 139,355  
|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) |  |   | (372,935)
|                                                                                               
|Pro Forma Net Income                                                                            | $ | 8,980,076 |  | $ | 2,234,949 |  | $ | 436,563  
|                                                                                               
|Income Per Common Share                                                                         |   |           |  |   |           |  |   |          
|Basic, as reported                                                                              | $ | 0.85      |  | $ | 0.31      |  | $ | 0.10     
|Basic, pro forma                                                                                |   | 0.80      |  |   | 0.28      |  |   | 0.06     
|                                                                                                |   |           |  |   |           |  |   |          
|Diluted, as reported                                                                            | $ | 0.75      |  | $ | 0.28      |  | $ | 0.09     
|Diluted, pro forma                                                                              |   | 0.71      |  |   | 0.26      |  |   | 0.06     
|                                                                                               

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.

Cumulative Effect of Change in
Accounting Principle  The Company adopted SFAS No. 143,
Accounting for Asset Retirement Obligations, on January 1, 2003. In accordance with
the transition provisions of SFAS No. 143, on that date the Company recorded asset
retirement costs and liabilities and recorded an adjustment for the cumulative effect on
prior years of adopting SFAS No. 143 in the amount of $11,813 as a reduction in
earnings, which had no effect on basic or diluted earnings per share.

Recent Accounting
Pronouncements  In December 2004, the FASB issued Statement No. 123
(Revised 2004), Share-Based Payment(Statement 123(R)). Statement
123(R) revises Statement No. 123, Accounting for Stock-Based Compensation, and
supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. Statement
123(R) requires companies to recognize the cost of employee services received in exchange
for stock options and awards of equity instruments based on the grant-date fair value of
such options and awards. The Company is required to adopt Statement 123(R) on a
prospective basis beginning on January 1, 2006, which will result in the recognition of
the remaining unrecognized stock-based compensation computed on a fair value basis over
the remaining vesting period. The effect of adopting Statement 123(R) will result in
recognition of $391,466 of additional after-tax compensation during the year ending
December 31, 2006 from options outstanding at December 31, 2005.

In December 2004, the FASB issued
SFAS Statement No. 153, Exchanges of Non-monetary Assetsan amendment of APB
Opinion No. 29. This Statement amends APB Opinion 29 to eliminate the exception for
non-monetary exchanges of similar productive assets and replaces it with a general
exception for exchanges of non-monetary assets that do not have commercial substance. A
non-monetary exchange has commercial substance if the future cash flows of the entity are
expected to change significantly as a result of the exchange. The Company implemented this
standard on January 1, 2006 and will not have a material impact to the Company.

---



# ARENA RESOURCES, INC.NOTES TO FINANCIAL
STATEMENTS

In March 2005, the FASB issued FASB
Interpretation (FIN) 47, Accounting for Conditional Asset Retirement
Obligations  an interpretation of FASB Statement No. 143.
FIN 47 clarifies that conditional asset retirement obligations meet the definition of
liabilities and should be recognized when incurred if their fair values can be reasonably
estimated. The Company adopted the provisions of FIN 47 effective December 31,
2005. The adoption of FIN 47 had no impact on the Companys financial position
or results of operations.

In May 2005, the FASB issued SFAS No.
154, Accounting Changes and Error Corrections  a replacement of APB Opinion No.
20 and FASB Statement No. 3.SFAS No. 154 applies to all voluntary changes in
accounting principle or when an accounting pronouncement does not include specific
transition provisions and changes the requirements for the accounting for and reporting of
a change in accounting principle. This statement requires retrospective application to
prior periods financial statements of changes in accounting principle, unless it is
impracticable to determine either the period specific effects or the cumulative effect of
the change. The Company implemented this standard on January 1, 2006 and will not have a
material impact to the Company.

In April 2005, the FASB issued FSP
19-1, Accounting for Suspended Well Costs.FSP 19-1 provides guidance on the
accounting for exploratory well costs. It states that for companies using the
successful efforts method of accounting for capitalized costs, if an exploratory well is
drilled but is not found to have proved reserves, even if it shows reserves, but the
reserves cannot be considered proved, then the capitalized costs of drilling the well are
expensed. This pronouncement does not impact the accounting for the Company because the
Company does not use the successful efforts method of accounting for capitalized costs.

In February 2006, the FASB issued
SFAS No. 155, Accounting for Certain Hybrid Financial
Instruments  an amendment of FASB Statements No. 133 and 140.
SFAS No. 155 resolves issues addressed in SFAS No. 133 Implementation
Issue No. D1, Application of Statement 133 to Beneficial Interests in Securitized
Financial Assets.  SFAS No. 155 will become effective for the
Companys fiscal year after September 15, 2006. The impact of SFAS No. 155 will
depend on the nature and extent of any new derivative instruments entered into after the
effective date.

# NOTE 2  EARNINGS
PER SHARE INFORMATION

|For the Years Ended December 31,                                       |   | 2005       |  |   | 2004      |  |   | 2003     
|---------------------------------------------------------------------- | - | ---------- |  | - | --------- |  | - | ---------
|                                                                      
|Income before cumulative effect of change in accounting   principle    | $ | 9,460,683  |  | $ | 2,451,652 |  | $ | 681,956  
|Cumulative effect of change in accounting principle                    |   | -          |  |   | -         |  |   | (11,813) 
|                                                                      
|Net Income                                                             | $ | 9,460,683  |  | $ | 2,451,652 |  | $ | 670,143  
|                                                                      
|Basic Weighted-Average Common Shares Outstanding                       |   | 11,164,070 |  |   | 7,873,213 |  |   | 6,759,858
|Effect of dilutive securities                                          |   |            |  |   |           |  |   |          
|Warrants                                                               |   | 838,773    |  |   | 524,173   |  |   | 231,476  
|Stock options                                                          |   | 597,263    |  |   | 296,792   |  |   | 250,342  
|                                                                      
|Diluted Weighted-Average Common Shares Outstanding                     |   | 12,600,106 |  |   | 8,694,178 |  |   | 7,241,676
|                                                                      
|Basic Earnings Per Share                                               |   |            |  |   |           |  |   |          
|Income before cumulative effect of change in accounting      principle | $ | 0.85       |  | $ | 0.31      |  | $ | 0.10     
|Net income                                                             |   | 0.85       |  |   | 0.31      |  |   | 0.10     
|                                                                       |   |            |  |   |           |  |   |          
|Diluted Earnings Per Share                                             |   |            |  |   |           |  |   |          
|Income before cumulative effect of change in accounting      principle | $ | 0.75       |  | $ | 0.28      |  | $ | 0.09     
|Net Income                                                             |   | 0.75       |  |   | 0.28      |  |   | 0.09     
|                                                                      

---



# ARENA RESOURCES, INC.NOTES TO 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 4. In addition, the Company paid acquisition costs of $28,000 and issued
15,000 shares of common stock valued at $90,000, or $6.00 per share, and 25,000 shares of
common stock valued at $149,750, or $5.99 per share, as a finders fee on the East
Hobbs San Andres Property acquisition. The total acquisition cost was allocated to the
assets acquired and the liabilities assumed as follows:

|Accounts receivable                            | $ | 165,544    |  |  | 
|---------------------------------------------- | - | ---------- |  |  | 
|Oil and gas properties subject to amortization |   | 10,189,480 |  |  | 
|                                              
|Total Assets                                   |   | 10,355,024 |  |  | 
|                                              
|Accounts payable                               |   | (21,872)   |  |  | 
|Asset retirement obligation                    |   | (56,782)   |  |  | 
|                                              
|Total Liabilities Assumed                      |   | (78,654)   |  |  | 
|                                              
|Net Asset Acquired                             | $ | 10,276,370 |  |  | 
|                                              

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, 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 acquisition
cost was allocated to the assets acquired and the liabilities assumed as follows:

---



# ARENA RESOURCES, INC.NOTES TO FINANCIAL
STATEMENTS

|Oil and gas properties subject to amortization | $ | 11,479,742 |  |  | 
|---------------------------------------------- | - | ---------- |  |  | 
|Asset retirement obligation                    |   | (513,247)  |  |  | 
|                                              
|Net Assets Acquired                            | $ | 10,966,495 |  |  | 
|                                              

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
and 2003, respectively:

|For the Years Ended December 31,                                  |             | 2004       |  |   | 2003     
|----------------------------------------------------------------- | ----------- | ---------- |  | - | ---------
|                                                                 
|                                                                  | (Unaudited)
|Oil and Gas Revenues                                              | $           | 11,493,181 |  | $ | 7,885,740
|Income from Operations Before Cumulative Effect of Change in      |             |            |  |   |          
|Accounting Principle                                              |             | 2,833,800  |  |   | 1,037,061
|Net Income                                                        |             | 2,833,800  |  |   | 1,025,248
|                                                                 
|Basic Income Per Common Share                                     |             |            |  |   |          
|Income before cumulative effect of change in accounting principle | $           | 0.36       |  | $ | 0.15     
|Net income                                                        |             | 0.36       |  |   | 0.15     
|Basic Income Per Common Share                                     |             |            |  |   |          
|Income before cumulative effect of change in accounting principle | $           | 0.33       |  | $ | 0.14     
|Net income                                                        |             | 0.33       |  |   | 0.14     
|                                                                 

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

Other Acquisitions On October 28, 2004, the Company issued 5,000 shares of common stock to an
unrelated party as a finders fee in connection with the purchase of a 70% interest
in the Gibralter well in Mississippi. The shares were valued at $34,500, or $6.90 per
share, based on the market value of the common stock on the date issued. Arena paid
$214,507 of the costs to drill the exploratory well in exchange for the jointly-operated
working interest in the well.

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 ranted
from 16.1% to 79.2%. Total acquisition costs, including 5,000 shares of restricted common
stock valued at $15.81 per share, or $79,050, totaled $1,406,588.

During 2005, the Company also
acquired the lease rights to a total of 19,840 acres in Hamilton and Greeley Counties,
Kansas. Total acquisition costs, including 20,000 shares of restricted common stock valued
at $13.08 per share, or $261,600, was $574,546. 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 was $735,000. These funds received were accounted for as an offset
to capitalized costs.

---



# ARENA RESOURCES, INC.NOTES TO FINANCIAL
STATEMENTS

# NOTE 4  NOTES
PAYABLE AND PUT OPTION

Notes Payable On April 14, 2004, the Company established a new $15,000,000 credit
facility from a bank with an $8,500,000 initial borrowing base. In April 2005, the Company
entered into an agreement that increased the facility to $50,000,000, with an increased
borrowing base of $35,000,000. Any increases in the borrowing base are subject to written
consent by the financial institution. The interest rate is a floating rate equal to the
30, 60 or 90 day LIBOR rate plus 2.25%, currently 7.11% per annum, and is payable monthly.
Amounts borrowed under the revolving credit facility are due on April 30, 2008. The
revolving credit facility is secured by the Companys principal mineral interests. 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. At December 31,
2005, the Company was in compliance with all covenants and no amounts were outstanding
under this credit facility, though $299,029 is reserved under the revolving credit
facility as collateral for standby letters of credit issued to various states.

Notes Payable to Related
Parties On July 1, 2002, the Board of Directors authorized the
Company to borrow up to $500,000 from its officers. On July 26, 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, 2007, 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, 2005 and 2004.

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 have 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 has
been 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. At the date of issuance,
the fair value of the liability was $160,379, calculated using the Black-Scholes option
pricing model with the following assumptions: 3% risk-free interest rate; 33% volatility;
2 years expected life; and 0% dividend yield. At December 31, 2004, the fair value of the
liability was $95,033, calculated using the Black-Scholes option pricing model with the
following assumptions: 3% risk-free interest rate; 34% volatility; 2 years expected life;
and 0% dividend yield. At December 31, 2005, the fair value of the liability was $0,
calculated using the Black-Scholes option pricing model with the following assumptions:
4.38% risk-free interest rate; 43.44% volatility; 1 years expected life; and 0% dividend
yield.

# NOTE 5  ASSET
RETIREMENT OBLIGATION

SFAS 143 provides accounting
requirements for retirement obligations associated with tangible long-lived assets,
including: 1) the timing of liability recognition; 2) initial measurement of the
liability; 3) allocation of asset retirement cost to expense; 4) subsequent measurement of
the liability; and 5) financial statement disclosures. SFAS 143 requires that an asset
retirement cost should be capitalized as part of the cost of the related long- lived asset
and subsequently allocated to expense using a systematic and rational method.

---



# ARENA RESOURCES, INC.NOTES TO FINANCIAL
STATEMENTS

At January 1, 2003, the
implementation of SFAS No. 143 resulted in a net increase in property and equipment
of $217,878. Liabilities increased by $236,718, which represents the establishment of an
asset retirement obligation liability. The cumulative effect on prior years of the change
in accounting principle of $11,813, net of $7,027 of related tax effects, was
recorded in the first quarter of 2003 as a reduction in earnings. The effect of adopting
this accounting principle was a $24,873 after-tax decrease in net income during the year
ended December 31, 2003.

The adoption of SFAS No. 143 will
affect amortization of oil and gas properties on an on-going basis. The increase in oil
and gas properties is being amortized as the related oil and gas reserves are produced,
and resulted in an increase in depreciation, depletion and amortization for the years
ended December 31, 2005, 2004 and 2003 of $21,619, $10,798 and $7,459, respectively. The
adoption of SFAS No. 143 also impacted the computation of the ceiling test for the
carrying value of oil and gas properties. The ceiling test has changed to include the
estimated asset retirement costs in the cost of oil and gas properties and exclude future
abandonment costs from the computation of the present value of estimated future net
revenues. This change only had a nominal effect on the Companys ceiling test
computation at December 31, 2005, 2004 and 2003.

The reconciliation of the asset
retirement obligation for the years ended December 31, 2003, 2004 and 2005 is as follows:

|Balance, January 1, 2003   | $ | 236,718   |  |  | 
|-------------------------- | - | --------- |  |  | 
|Liabilities incurred       |   | 338,270   |  |  | 
|Accretion expense          |   | 32,212    |  |  | 
|                          
|Balance, December 31, 2003 |   | 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 |  |  | 
|                          

# NOTE 6 
STOCKHOLDERS EQUITY

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

Preferred Stock
 There is no preferred stock outstanding.

Common Stock
 On August 22, 2002, the Company initiated a $3,000,000 private placement offering
of the Companys common stock at $2.50 per share with a detachable warrant
exercisable at $5.00 per share through September 30, 2005. From January 1, 2003 to July
15, 2003, the Company issued 790,294 shares of common stock and 790,294 warrants for
$1,711,200 in net cash proceeds (net of cash offering costs of $264,535). In addition,
105,196 warrants exercisable at $5.00 per share through September 30, 2005 were issued to
placement agents. The net proceeds received were allocated to the common stock and the
warrants based upon their relative fair values, with $1,275,046 allocated to the common
stock and $436,154 allocated to the warrants. The fair value of the warrants issued was
$1,192,626, or $1.37 per warrant, which was determined using the Black-Scholes option
pricing model with the following weighted-average assumptions: risk-free interest rate of
1.32%, expected dividend yield of 0%, volatility of 34.7% and an expected life of 2.21
years.

---



# ARENA RESOURCES, INC.NOTES TO FINANCIAL
STATEMENTS

In addition, during the year ended
December 31, 2003, Arena issued 2,433 additional warrants, with the same terms to
placement agents, and 50,000 additional warrants exercisable at $3.00 per share through
July 15, 2006, as consulting fees, relating to the shares of common stock and warrants
issued during 2002. During the year ended December 31, 2003, $15,922 of the proceeds from
the 2002 cash offering proceeds were allocated to the additional warrants, based upon
their relative fair value. The offering closed July 15, 2003. The Company issued a total
of 1,076,294 units of common stock and warrants to investors under the offering for
$2,313,336 in net cash proceeds (net of cash offering costs of $377,399) and issued
157,629 warrants as consulting fees and for services to placement agents.

During the year ended December 31,
2003, warrant holders exercised 19,400 warrants with an exercise price of $1.75 for
$33,950. Additionally, in 2003 the Company issued 70,847 shares of common stock for
services, which the Company valued at an aggregate total of $394,590, or $5.57 per share.
The Company capitalized as part of oil and gas properties $319,550 and the remaining
$75,040 was charged to expense.

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 options 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.

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.

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.

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.

---



# ARENA RESOURCES, INC.NOTES TO FINANCIAL
STATEMENTS

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.

Additionally, in 2005 the Company
issued 25,000 shares of common stock for services, as described in Note 3. Of the 25,000,
5,000 shares were valued at an aggregate of $79,050, or $15.81 per share, and 20,000 shares were valued at
an aggregate of $261,600, or $13.08 per share. The Company capitalized as part of oil and
gas properties the full $340,650.

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

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 as disclosed further in Note 6.

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 effect 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 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.

Stock purchase warrants issued and exercised during the years ended December 31, 2005,
2004, and 2003 are summarized as follows:

|                                     | 2005        |                                 | 2004 |           | 2003                           
|------------------------------------ | ----------- | ------------------------------- | ---- | --------- | -------------------------------
|                                     |             |                                 |      |           |                                
|                                     | Warrants    | Weighted-Average Exercise Price |      | Warrants  | Weighted-Average Exercise Price
|                                    
|Outstanding at beginning of the year | 3,314,923   | $  4.47                         |      | 1,435,723 | $4.47                          
|Issued                               | 29,126      | $10.30                          |      | 1,957,500 | $7.46                          
|Expired                              | (4,650)     | $  4.33                         |      | -         | $      -                       
|Exercised                            | (2,971,273) | $  6.10                         |      | (78,300)  | $4.52                          
|                                    
|Outstanding at End of Year           | 368,126     | $  7.69                         |      | 3,314,923 | $6.23                          
|                                    

Stock purchase warrants outstanding
at December 31, 2005 are as follows:

---



# ARENA RESOURCES, INC.NOTES TO FINANCIAL
STATEMENTS

|WarrantsOutstanding | Exercise Price | Weighted-AverageRemainingContractual Life
|------------------- | -------------- | -----------------------------------------
|                    |                |                                          
|50,000              | $3.00          | 0.7                                      
|145,000             | 7.49           | 3.6                                      
|144,000             | 9.00           | 3.6                                      
|29,126              | 10.30          | 5.0                                      
|                   
|368,126             |                |                                          
|                   

# NOTE 7  EMPLOYEE
STOCK OPTIONS

On April 1, 2003 and on August 12,
2003, the Company granted nonqualified stock options to directors and employees to
purchase 1,000,000 shares and 50,000 shares of common stock at $3.70 per share and $4.80
per share through April 1, 2008 and August 12, 2008, respectively. Effective July 31,
2003, 50,000 of the options with an exercise price of $3.70 per share were forfeited. The
exercise price of the options granted in 2003 was 85% of the market value of the
Companys common stock on the dates issued. The Company recognizes compensation
expense related to the 15% discount amount of the exercise price from the market price of
the stock at the date of grant over the five year vesting period of the options. The
Company recognized compensation expense for the years ended December 31, 2003, 2004 and
2005 of $221,198, $204,525 and $118,732, respectively.

Additionally, on January 3, 2005 and
October 20, 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.

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, 2005 and changes during the years ended
December 31, 2005, 2004 and 2003 is as follows:

|                                                               | 2005      | 2004 | 2003                           
|-------------------------------------------------------------- | --------- | ---- | -------------------------------
|                                                               |           |      |                                
|                                                               | Options   |      | Weighted-Average Exercise Price
|                                                              
|Outstanding at beginning of the year                           | 1,000,000 |      | $3.76                          
|Issued                                                         | 425,000   |      | 9.78                           
|Forfeited                                                      | -         |      | -                              
|                                                              
|Outstanding at end of year                                     | 1,425,000 |      | 5.55                           
|                                                              
|Exercisable at end of  year                                    | 400,000   |      | $3.76                          
|                                                              
|Weighted average fair value of options granted during the year |           |      | $3.37                          
|                                                              

---



# ARENA RESOURCES, INC.NOTES TO FINANCIAL
STATEMENTS

|                                |           |                    | Options Outstanding |                                                        |        
|------------------------------- | --------- | ------------------ | ------------------- | ------------------------------------------------------ | -------
|                                |           |                    |                     |                                                        |        
|Exercise price                  |           | Number Outstanding |                     | Weighted-Average Remaining Contractual Life (in years) |        
|                               
|$                               | 3.70      |                    | 950,000             |                                                        | 2.3    
|$                               | 4.80      |                    | 50,000              |                                                        | 2.6    
|$                               | 8.30      |                    | 375,000             |                                                        | 4.0    
|$                               | 20.85     |                    | 50,000              |                                                        | 4.9    
|                               
|Total outstanding               | 1,425,000 |                    | 2.8                 |                                                        | 400,000
|                               
|Weighted average exercise price | 5.55      |                    |                     |                                                        |        
|                               

The fair value of the options granted during 2005 and 2003, net of forfeitures,
were estimated at the date of grant using a Black-Scholes option-pricing model
with the following weighted-average assumptions: expected volatility of 32.3%
and 36.2%, respectively, risk-free interest rate of 3.73% and 2.9%,
respectively, zero dividend yield and expected lives of 5.0 years.

# NOTE 8  RELATED
PARTY TRANSACTIONS

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

# NOTE 9  COMMITMENTS

Operating Leases
Effective January 1, 2004, the Company entered into a
two-year extension to an existing operating lease agreement for office space. On
March 21, 2005 and effective May 1, 2005, the Company leased additional footage
in the same facility. Under terms of the lease, the Company pays $2,500 per
month through December 31, 2006. The Company incurred lease expense of $28,000
for the year ended December 31, 2005. The future minimum lease payments under
the operating lease agreement as of December 31, 2005 consist of $30,000 due
during the year ending December 31, 2006.

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 $299,029 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 10  INCOME
TAXES

At December 31, 2005, the Company had alternative minimum income tax payable of
$329,986. The provision for income taxes consisted of the following:

---



# ARENA RESOURCES, INC.NOTES TO FINANCIAL
STATEMENTS

|For the Years Ended December 31, |  | 2005      |  |  | 2004      |  |  | 2003   
|-------------------------------- |  | --------- |  |  | --------- |  |  | -------
|                                
|Current - federal                |  | 365,606   |  |  | -         |  |  | -      
|Deferred - state                 |  | 753,842   |  |  | 265,828   |  |  | 52,772 
|Deferred - federal               |  | 4,508,678 |  |  | 1,131,246 |  |  | 349,683
|                                
|Provision for income taxes       |  | 5,628,126 |  |  | 1,397,074 |  |  | 402,455
|                                

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

|For the Years Ended December 31,    |   | 2005      |  |   | 2004      |  |   | 2003    
|----------------------------------- | - | --------- |  | - | --------- |  | - | --------
|                                   
|Tax at federal statutory rate (34%) | $ | 5,130,195 |  | $ | 1,308,567 |  | $ | 368,700 
|Income not subject to tax           |   | -         |  |   | (24,493)  |  |   | (17,365)
|State tax, net of federal benefit   |   | 497,931   |  |   | 127,008   |  |   | 51,120  
|Effect of lower effective tax rates |   | -         |  |   | (14,008)  |  |   | -       
|                                   
|Provision for income taxes          | $ | 5,628,126 |  | $ | 1,397,074 |  | $ | 402,455 
|                                   

As of December 31, 2005, the Company had net operating loss and IDC carry
forwards for federal income tax reporting purposes of $8,770,000 which, if
unused, will expire in 2022 and 2025. 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 $401,109 minimum tax credit has an unlimited
carryover period.

The net deferred tax liability
consisted of the following:

|December 31,                         |  | 2005       |  |  | 2004      |  |  | 
|------------------------------------ |  | ---------- |  |  | --------- |  |  | 
|                                    
|Deferred tax liabilities             |  |            |  |  |           |  |  | 
|Property and equipment               |  | 11,102,307 |  |  | 2,163,239 |  |  | 
|                                    
|Total deferred tax liabilities       |  | 11,102,307 |  |  | 2,163,239 |  |  | 
|                                    
|Deferred tax assets                  |  |            |  |  |           |  |  | 
|Stock-based compensation             |  | 203,078    |  |  | 158,003   |  |  | 
|Minimum tax credit                   |  | 401,109    |  |  | -         |  |  | 
|Operating loss and IDC carryforwards |  | 3,310,511  |  |  | 33,246    |  |  | 
|                                    
|Total deferred tax assets            |  | 3,914,698  |  |  | 191,249   |  |  | 
|                                    
|Net deferred income taxes            |  | 7,187,609  |  |  | 1,971,990 |  |  | 
|                                    

# NOTE 11 
SUBSEQUENT EVENTS (UNAUDITED)

Subsequent to December 31, 2005, the Company issued 120,800 shares of restricted
common stock to reacquire the working interests and related rights in the Kansas
properties discussed in Note 3.

Subsequent to December 31, 2005, the Company issued 6,200 shares of restricted
common stock as a finders fee for the drilling rig the Company is in the process
of acquiring.

Subsequent to December 31, 2005, the
Company issued 29,126 warrants, exercisable at $10.30 per share. The warrants have an
estimated life of 5 years from the date of issuance. The fair value of these warrants will
be accounted for as other financing expense in 2006.

Subsequent to December 31, 2005, the
Company has borrowed $3,500,000 on our credit facility described in Note 4.

# NOTE 12  QUARTERLY
FINANCIAL DATA (UNAUDITED)

Quarterly
financial information is presented in the following summary:

---



# ARENA RESOURCES, INC.NOTES TO FINANCIAL
STATEMENTS

|                             | 2004              
|---------------------------- | ------------------
|                             |                   
|                             | Three Months Ended
|                             |                   
|                             |                   
|                             |                   
|Revenues                     | $                 
|Operating Income             |                   
|Net Income                   |                   
|Basic Net Income Per Share   | $                 
|Diluted Net Income Per Share |                   

|                             | 2005              
|---------------------------- | ------------------
|                             |                   
|                             | Three Months Ended
|                             |                   
|                             |                   
|                             |                   
|Revenues                     | $                 
|Operating Income             |                   
|Net Income                   |                   
|Basic Net Income Per Share   | $                 
|Diluted Net Income Per Share |                   

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

# NOTE 13 
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)

Capitalized Costs Relating to Oil
and Gas Producing Activities

|December 31,                                   |   | 2005        |  |   | 2004        |  |   | 2003     
|---------------------------------------------- | - | ----------- |  | - | ----------- |  | - | ---------
|                                              
|Unproved oil and gas properties                | $ | 692,783     |  | $ | 388,581     |  | $ | 128,694  
|Proved oil and gas properties                  |   | 69,077,903  |  |   | 34,068,557  |  |   | 8,334,706
|Drilling advances on uncompleted projects      |   | -           |  |   | 900,000     |  |   | 351,000  
|Advances on the acquisition of drilling rig    |   | 1,191,126   |  |   | -           |  |   | -        
|Support and office equipment                   |   | 132,863     |  |   | 87,087      |  |   | 67,458   
|                                              
|Total capitalized costs                        |   | 71,094,675  |  |   | 35,444,225  |  |   | 8,881,858
|Less accumulated depreciation and amortization |   | (4,346,628) |  |   | (1,565,124) |  |   | (559,229)
|                                              
|Net Capitalized Costs                          | $ | 66,748,047  |  | $ | 33,879,101  |  | $ | 8,322,629
|                                              

Costs Incurred in Oil and Gas
Producing Activities

|For the Years Ended December 31,                                          |   | 2005       |  |   | 2004       |  |   | 2003     
|------------------------------------------------------------------------- | - | ---------- |  | - | ---------- |  | - | ---------
|                                                                         
|Acquisition of proved properties                                          |   | 1,406,588  |  |   | 21,706,166 |  |   | 2,692,039
|Acquisition of unproved properties (net of proceeds from   property sale) |   | (160,454)  |  |   | 43,082     |  |   | 147,000  
|Exploration costs                                                         |   | 464,656    |  |   | 216,805    |  |   | 326,410  
|Development costs                                                         |   | 32,557,989 |  |   | 4,027,754  |  |   | 849,864  
|                                                                         
|Total Costs Incurred                                                      | $ | 34,268,779 |  | $ | 25,993,807 |  | $ | 4,015,313
|                                                                         

Results of Operations from Oil and
Gas Producing Activities The Companys results of operations from oil and
gas producing activities exclude interest expense, accretion expense, gain from change in
fair value of put options and the cumulative effect of change in accounting principle.
Income taxes are based on statutory tax rates, reflecting allowable deductions.

|For the Years Ended December 31,                             |   | 2005        |  |   | 2004        |  |   | 2003       
|------------------------------------------------------------ | - | ----------- |  | - | ----------- |  | - | -----------
|                                                            
|Oil and gas revenues                                         | $ | 25,843,077  |  | $ | 8,482,130   |  | $ | 3,665,477  
|Production costs                                             |   | (3,832,487) |  |   | (1,975,835) |  |   | (1,149,136)
|Production taxes                                             |   | (1,939,739) |  |   | (629,703)   |  |   | (269,563)  
|Depreciation, depletion, amortization and accretion          |   | (2,884,089) |  |   | (1,011,602) |  |   | (360,282)  
|General and administrative (exclusive of corporate overhead) |   | (613,762)   |  |   | (313,953)   |  |   | (221,498)  
|                                                            
|Results of operations before income taxes                    |   | 16,573,000  |  |   | 4,551,037   |  |   | 1,664,998  
|Provision for income taxes                                   |   | (6,132,010) |  |   | (1,683,884) |  |   | (616,049)  
|                                                            
|Results of Oil and Gas Producing Operations                  | $ | 10,440,990  |  | $ | 2,867,153   |  | $ | 1,048,949  
|                                                            

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.

---



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

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,          | 2005       |            | 2004 |            | 2003     
|----------------------------------------- | ---------- | ---------- | ---- | ---------- | ---------
|                                          |            |            |      |            |          
|                                          | Oil (1)    | Gas (1)    |      | Oil (1)    | Gas (1)  
|                                          |           
|Proved Developed and Undeveloped Reserves
|Beginning of year                         | 19,550,664 | 9,999,541  |      | 7,050,167  | 3,408,754
|Purchases of minerals in place            | 882,460    | 377,179    |      | 8,764,087  | 6,431,437
|Improved recovery and development         | 2,546,477  | 19,188,896 |      | -          | 640,000  
|Production                                | (441,995)  | (398,611)  |      | (195,167)  | (169,002)
|Revision of previous estimate             | 2,329,583  | 2,815,074  |      | 3,931,577  | (311,648)
|                                         
|End of year                               | 24,867,189 | 31,982,079 |      | 19,550,664 | 9,999,541
|                                         
|Proved Developed at end of year           | 7,885,115  | 22,480,279 |      | 4,721,293  | 4,615,265
|                                         

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

Standard Measure of Discounted Cash
Flows

|December 31,                                           |   | 2005          |  |   | 2004          |  |   | 2003        
|------------------------------------------------------ | - | ------------- |  | - | ------------- |  | - | ------------
|                                                      
|Future cash flows                                      | $ | 1,629,948,750 |  | $ | 814,346,791   |  | $ | 218,026,254 
|Future production costs                                |   | (281,685,991) |  |   | (171,518,828) |  |   | (64,157,199)
|Future development costs                               |   | (95,765,594)  |  |   | (61,975,106)  |  |   | (13,609,384)
|Future income taxes                                    |   | (423,161,523) |  |   | (187,392,403) |  |   | (45,778,941)
|                                                      
|Future net cash flows                                  |   | 829,335,642   |  |   | 393,460,454   |  |   | 94,480,730  
|10% annual discount for estimated timing of cash flows |   | (383,735,076) |  |   | (188,219,704) |  |   | (49,474,633)
|                                                      
|Standardized Measure of Discounted Cash Flows          | $ | 445,600,566   |  | $ | 205,240,750   |  | $ | 45,006,097  
|                                                      

---



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

# Changes in Standardized Measure
of Discounted Future Net Cash Flows

|For the Years Ended December 31,                                    |   | 2005          |  |   | 2004         |  |   | 2003       
|------------------------------------------------------------------- | - | ------------- |  | - | ------------ |  | - | -----------
|                                                                   
|Beginning of the year                                               | $ | 205,240,750   |  | $ | 45,006,097   |  | $ | 27,997,824 
|Purchase of minerals in place                                       |   | 33,405,120    |  |   | 142,824,938  |  |   | 21,333,720 
|Extensions, discoveries and improved recovery,   less related costs |   | 5,962,820     |  |   | 347,652      |  |   | 691,469    
|Development costs incurred during the year                          |   | 189,832,736   |  |   | 5,387,638    |  |   | 320,102    
|Sales of oil and gas produced, net of production   costs            |   | (21,991,034)  |  |   | (5,876,333)  |  |   | (2,302,405)
|Accretion of discount                                               |   | 28,467,073    |  |   | 4,882,064    |  |   | 3,012,793  
|Net changes in price and production costs                           |   | 191,917,618   |  |   | 74,777,221   |  |   | 8,222,075  
|Net change in estimated future development costs                    |   | (36,307,702)  |  |   | (3,187,159)  |  |   | 39,219     
|Revision of previous quantity estimates                             |   | 87,175,031    |  |   | 42,149,044   |  |   | (53,098)   
|Revision of estimated timing of cash flows                          |   | (111,387,288) |  |   | (27,509,967) |  |   | (5,468,732)
|Net change in income taxes                                          |   | (126,714,558) |  |   | (73,560,445) |  |   | (8,786,870)
|                                                                   
|End of the Year                                                     | $ | 445,600,566   |  | $ | 205,240,750  |  | $ | 45,006,097 
|                                                                   

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