United States Securities and Exchange Commission

United States Securities and Exchange Commission

Washington, D.C. 20549


Form 10-KSB

(Mark One)

þ

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

 

For the fiscal year ended December 31, 2003

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.
(Name of small business issuer in its charter)




Nevada

 

73-1596109

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification Number)

   

4920 South Lewis Avenue, Suite 107

Tulsa, Oklahoma

 

74105

(Address of Principal Executive Offices)

 

(Zip Code)


(918) 747-6060

(Issuer’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

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

Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B is not contained in this form, and no disclosure will 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-KSB or any amendment to this Form 10-KSB. þ

State issuer’s revenues for its most recent fiscal year.  $3,665,477

As of March 10, 2004, the aggregate market value of the common voting stock held by non-affiliates of the issuer, based upon the closing stock price of $6.70 per share, was approximately $31,710,410. As of March 10, 2004, the issuer had outstanding 7,167,097 shares of common stock ($0.001 par value).

Transitional Small Business Disclosure Format (check one): Yes ¨ No þ
















TABLE OF CONTENTS


PART I

Page


Item 1

Description of Business

3


Item 2

Description of Property

7


Item 3

Legal Proceedings

18


Item 4

Submission of Matters to a Vote of Security Holders

18


PART II


Item 5

Market for Registrant’s Common Equity; Related Stockholder Matters and Small

Business Issuer Purchases of Equity Securities

18


Item 6

Management’s Discussion and Analysis of Financial Condition and Results

of Operations

20


Item 7

Financial Statements

28


Item 8

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

28


Item 8A

Controls and Procedures

28


PART III


Item 9

Directors and Executive Officers

29


Item 10

Executive Compensation

32


Item 11

Security Ownership of Certain Beneficial Owners and Management and Related

Stockholder Matters

35


Item 12

Certain Relationships and Related Transactions

36


Item 13

Exhibits and Reports on Form 8-K

36


Item 14

Principal Accountant Fees and Services

37



2











Forward Looking Statements


All statements, other than statements of historical fact included in this Annual Report on Form 10-KSB (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.


We are engaged in oil and natural gas acquisition, exploration, development and production, with activities currently in Oklahoma, Texas, New Mexico and Kansas. Our intermediate-term focus is on pursuing acquisition of oil and gas properties that provide immediate cash flow, as well as opportunities for further development.  Our intent is to minimize our near-term risks, and to increase exploration activities once we have established a larger production base.


Business Development


Since our inception in August 2000, we have built our asset base and achieved growth primarily through property acquisitions. Finding properties that are suitable for our intermediate-term plans can sometimes be difficult, since we look for properties with development potential as well as existing cash flow.  We believe the key to being successful is in undertaking thorough due diligence of each property we acquire or consider for acquisition.  


From our inception through December 31, 2003, we have increased our proved reserves to approximately 9.5 million Boe (barrel of oil equivalent), through the acquisition of interests in 10 leases, which have net revenue interests ranging from 24.5% to 81.32%.  As of December 31, 2003, our estimated proved reserves had a pre-tax PV10 (present value of future net revenues before income taxes discounted at 10%) of approximately $92 million. We spent approximately $6.26 million on acquisitions and capital projects during 2002 and 2003.


3











We have a portfolio of oil and natural gas reserves, with approximately 94% of our proved reserves consisting of oil and approximately 6% consisting of natural gas. Approximately 18% of our proved reserves are classified as proved developed producing, or “PDP.” Approximately 2% of our proved reserves are classified as proved developed non-producing, or “PDNP,” and approximately 80% 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 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 2003, three customers were responsible for generating 81% or more of our total oil and natural gas sales.  These three customers were Plains Marketing, L.P.,. accounting for approximately 51% of total sales, Sun Oil Company, accounting for approximately 19% of total sales and Navajo Refining Company, accounting for approximately 11% of total sales.  However, we believe that the loss of any one of these customers would not materially impact our business, because we could readily find other purchasers for our oil and gas as produced.


4










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 prorationing 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.



5










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.



6










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, 2003, we had seven full-time employees, including one petroleum engineer. 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 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, 2003, our proved reserves have grown to 9,487,043 Boe, at an average all-in finding cost of $0.83 per Boe. As of December 31, 2003, our estimated proved reserves had a pre-tax PV10 value of approximately $92 million, approximately 40% of which came from properties located in Texas, approximately 36% from our properties in Oklahoma and approximately 23% from our properties in New Mexico. We spent approximately $6.26 million on capital projects during 2002 and 2003, including approximately $4.79 million for the acquisition of 6.85 million Boe of proved reserves (estimated as of the date of acquisition). We expect to further develop these properties through additional drilling. We have budgeted approximately $10 million for capital expenditures in 2004, all of which is targeted for the acquisition of additional reserves.  We anticipate that we will soon seek additional capital as a source of a portion of the funding for this acquisition strategy.  Other funds to finance potential acquisitions will come from cash flow from operations and, if necessary, from drawing on our credit facility. We believe that our acquisition expertise, together with our operating experience and efficient cost structure, provides us with the potential to continue our growth.


We have a portfolio of oil and natural gas reserves, with approximately 94% of our proved reserves consisting of oil and approximately 6% consisting of natural gas. Approximately 18% of our proved reserves are classified as proved developed producing properties. Approximately 2% of our proved reserves are classified as proved developed non-producing, and approximately 80% are classified as proved undeveloped.



7










The following table summarizes our total net proved reserves and pre-tax PV10 value as of December 31, 2003.


Proved Developed and Undeveloped Reserves


Geographic Area

Oil

(Bbl)

 

Natural

Gas (Mcf)

 

Total

(Boe)

 

Pre-Tax PV10 Value

Oklahoma

3,465,351

 

658,484

 

3,575,099

$

32,623,882

Texas

2,729,338

 

1,107,544

 

2,913,929

 

36,937,529

New Mexico

2,724,228

 

394,484

 

2,789,975

 

20,820,341

Kansas

--

 

1,248,242

 

208,040

 

1,583,620

 


 


 


 


Total

8,918,917

 

3,408,754

 

9,487,043

$

91,965,372


Proved Reserves


Our 9,487,043 Boe of proved reserves, which consist of approximately 94% oil and 6% natural gas, are summarized below as of December 31, 2003, on a net pre-tax PV10 value basis. Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC).


As of December 31, 2003, our proved reserves in Texas had a net pre-tax PV10 value of $36.9 million, our Oklahoma proved reserves had a net pre-tax PV10 value of $32.6 million and our proved reserves in New Mexico had a net pre-tax PV10 value of $20.8 million. Collectively, these three areas represented approximately $90.4 million, or 98%, of our total proved reserve net pre-tax PV10 value of $92 million as of December 31, 2003.


As of December 31, 2003, approximately 18% of the 9.5 million Boe of proved reserves have been classified as proved developed producing, or “PDP”. Proved developed non-producing, or “PDNP”, and proved undeveloped, or “PUD”, reserves constitute 1% and 81%, respectively, of the proved reserves as of December 31, 2003.


Total proved reserves had a net pre-tax PV10 value as of December 31, 2003 of approximately $92 million, 16% or $14.3 million of which is associated with the PDP reserves. An additional $851,000 is associated with the PDNP reserves ($15.2 million for total proved developed reserves, or 16.5% of total proved reserves’ pre-tax PV10 value) and $76.8 million is associated with PUD reserves.



8









Our proved reserves as of December 31, 2003 are summarized in the table below.


 

  

Oil

(Bbl)

  

Natural Gas

(Mcf)

  

Total

(Boe)

  

% of Total

Proved

 

Pre-tax PV10

(In thousands)

  

Future Capital

Expenditures

(In thousands)

Oklahoma:

  

 

  

 

  

 

  

 

 

 

 

  

 

 

PDP

  

736,427

 

658,484

 

846,175

  

9

%

$

7,707

  

$

--

PDNP

  

--

 

--

 

--

  

0

%

 

--

  

 

--

PUD

  

2,728,924

 

--

 

2,728,924

  

29

%

 

24,917

  

 

5,275

 

  

     

  

    

  

  

Total Proved:

  

3,465,351

 

658,484

 

3,575,09

  

38

%

$

32,624

  

$

5,275

 

  

 

  

 

  

 

  

    

  

  

Texas:

  

 

  

 

  

 

  

 

 

 

 

  

 

 

PDP

  

349,598

 

136,747

 

372,389

 

4

%

$

3,235

  

$

--

PDNP

  

--

 

--

 

--

 

0

%

 

--

  

 

--

PUD

  

2,379,740

 

970,797

 

2,541,540

 

27

%

 

33,702

  

 

4,200

 

  

          

  

  

Total Proved:

  

2,729,338

 

1,107,544

 

2,913,929

 

31

%

$

36,937

  

$

4,200

 

  

 

  

 

  

 

  

    

  

  

New Mexico:

  

 

  

 

  

 

  

 

 

 

 

  

 

 

PDP

  

494,496

 

209,047

 

529,337

 

6

%

$

3,407

  

$

--

PDNP

  

--

 

--

 

--

 

0

%

 

--

  

 

--

PUD

  

2,229,732

 

185,437

 

2,260,638

 

23

%

 

17,413

  

 

6,014

 

  

          

  

  

Total Proved:

  

2,724,228

 

394,484

 

2,789,975

 

29

%

$

20,820

  

$

6,014

 

  

          

  

  

Kansas:

  

 

  

 

  

 

  

 

 

 

 

  

 

 

PDP

  

--

 

--

 

--

 

0

%

$

--

  

$

--

PDNP

  

--

 

608,460

 

101,410

 

1

%

 

852

  

 

--

PUD

  

--

 

639,782

 

106,630

 

1

%

 

732

  

 

120

               

Total Proved:

  

--

 

1,248,242

 

208,040

 

2

%

$

1,584

  

$

120

 

  

          

  

  

 

  

          

  

  

Total:

  

       

 

 

 

  

 

 

PDP

  

1,580,521

 

1,004,278

 

1,747,901

 

18

%

$

14,349

  

$

--

PDNP

  

--

 

608,460

 

101,410

 

1

%

 

852

  

 

--

PUD

  

7,338,396

 

1,796,016

 

7,637,732

 

81

%

 

76,764

  

 

15,609

 

  

 

  

 

  

 

  

    

  

  

Total Proved:

  

8,918,917

 

3,408,754

 

9,487,043

 

100

%

$

91,965

  

$

15,609


Production


Our estimated average daily production for the month of December, 2003, is summarized below. These tables indicate the percentage of our estimated December 2003 average daily production of 420 Boe/d attributable to each state and to oil versus natural gas production.



9

 










Average Daily Production (December 2003): 420 Boe/d

    State

Average Daily Production

 

Oil

 

Natural Gas

 
       

Oklahoma

49.15

%

45.65

%

3.50

%

       

Texas

24.62

%

23.84

%

0.78

%

       

New Mexico

26.23

%

23.37

%

2.86

%

       

Kansas

--

%

--

%

--

%

       

Total

100

%

92.86

%

7.14

%


Summary of Oil and Natural Gas Properties and Projects


Significant Oklahoma Operations


Casey Lease – Muskogee County, Oklahoma.    The Casey Lease originally consisted of a 40% working interest contributed by our two principal shareholders.  We subsequently acquired additional interests in this lease, so that presently we have a 94% working interest, and an approximately 74.48% net revenue interest in the well on this property. This lease consists of approximately 160 acres.  In December 2003 we temporarily shut-in this gas well.  We anticipate that we will attempt to recomplete this well in another zone in the future, to bring it back into production.


Ona Morrow Sand Unit – Cimarron and Texas Counties, Oklahoma.    We own a 100% working interest and an 81.32% net revenue interest in this lease which has been producing since our acquisition in July 2002.  This lease has approximately 2,120 acres and seven producing wells.  We believe up to five additional locations may be suitable for drilling, which are included in our estimate of our PUD.


Eva South Morrow Sand Unit – Texas County, Oklahoma.    We own a 100% working interest and an 85.41% net revenue interest in this lease which was also acquired in July 2002. The lease consists of approximately 489 acres and has seven producing wells, with a possibility for two additional wells, which have been included in our estimate of our PUD.


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 five producing wells, and we believe there are up to three additional drilling locations on these leases.  The Hanes lease contains approximately 640 acres and four producing wells, with a possibility of up to two additional wells, which are included in our estimate of PUD.


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 that we do not operate.  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.



10











Significant Texas Operations


Y6 Lease – Fisher County, Texas.    We acquired a 100% working interest and an 80% net revenue interest in this lease in June 2001.  There are currently 12 producing wells on this lease.  A portion of this property has been waterflooded, and when we begin our future development operations on this property, we plan to waterflood the remaining acreage. This potential waterflood project (and the estimated cost thereof) is included as PUD in our reserve report.  This lease consists of approximately 2,073 acres.


Dodson Lease – Montague County, Texas.    We purchased a 100% working interest and an 81.25% net revenue interest in this lease in June 2002.  There are currently three producing wells and nine other wells on this approximately 570 acre lease.  We anticipate utilizing the nine nonproducing wells for waterflood recovery purposes when we begin to develop this property.  This potential waterflood (and the estimated cost thereof) is included as PUD in our reserve report.


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. The lease covers approximately 1,200 acres, and currently has 10 producing wells.  We believe it can support up to four additional wells, which are included in our estimate of PUD.


Significant New Mexico Operations


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.  There are currently 43 producing wells on this lease, and we believe it can support six to eight possible infill wells, as well as some untested formations in shallow sand. This lease consists of approximately 2,240 acres.


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


Significant Kansas Operations


Auntie Em Lease – Haskell County, Kansas. After entering into a farmout agreement in March 2002, we drilled and completed an initial gas well on this lease.  This well is not yet producing, pending connection to the pipeline. After payout, we will own a 75% working interest and a 60% net revenue interest in this property.  This lease consists of approximately 800 acres.  In January 2004 we drilled and completed a second well on this acreage.  The well was successful and is pending connection to the pipeline, and we believe one additional well may be drilled on this property, which is included in our estimate of PUD. In 2004 we also leased an additional 160 acres that offset this property.


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. During August 2003 we drilled one well on this acreage, which was unsuccessful and was plugged and abandoned.



11









Acreage


The following table summarizes gross and net developed and undeveloped acreage at December 31, 2003 by region (net acreage is our percentage ownership of gross acreage). Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.


 

  

Developed Acreage

  

Undeveloped Acreage

  

Total Acreage

 

  

Gross

  

Net

  

Gross

  

Net

  

Gross

  

Net

Oklahoma

  

5,689

 

4,222

 

--

 

--

 

5,689

 

4,222

 

  

           

Texas

  

3,464

 

2,773

 

376

 

301

 

3,840

 

3,074

 

  

           

New Mexico

  

4,040

 

2,661

 

--

 

--

 

4,040

 

2,661

             

Kansas

  

160

 

128

 

2,200

 

1,773

 

2,360

 

1,901

 

  

           

Total

  

13,353

 

9,784

 

2,576

 

2,074

 

15,929

 

11,858

 

  

 

  

 

  

 

  

 

  

 

  

 


Production History


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


 

  

Year Ended December 31,

 

  

2001

  

2002

  

2003

Oil production (Bbls)

  

 

12,895

  

 

59,468

 

 

117,646

Natural gas production (Mcf)

  

 

4,776

  

 

47,985

 

 

65,417

Total production (Boe)

  

 

13,691

  

 

67,465

 

 

128,549

Daily production (Boe/d)

  

 

38

  

185

 

 

352

Average sales prices:

  

 

 

  

 

  

 

 

Oil (per Bbl)

  

$

22.36

  

$

25.76

 

$

29.06

Natural gas (per Mcf)

  

 

1.79

  

 

2.60

 

 

3.78

Total (per Boe)

  

 

21.69

  

 

24.56

 

 

28.51

Average production cost (per Boe)

  

$

7.81

  

8.82

 

8.94


In December 2003, we temporarily shut-in a well that accounted for approximately 11% of our natural gas production in 2003.  The remaining natural gas production comes from our wells that are primarily oil producers.



12









Productive Wells


The following table presents our ownership at December 31, 2003, in productive oil and natural gas wells by region (a net well is our percentage ownership of a gross well).


 

  

Oil Wells

  

Natural Gas

Wells (1)

  

Total Wells

 

  

Gross

  

Net

  

Gross

  

Net

  

Gross

  

Net

             

Oklahoma

  

23

 

16.53

 

--

 

--

 

23

 

16.53

 

  

           

Texas

  

25

 

20.00

 

--

 

--

 

25

 

20.00

 

  

 

  

 

  

 

  

 

  

 

  

 

New Mexico

  

64

 

40.49

 

--

 

--

 

64

 

40.49

             

Kansas

  

--

 

--

 

--

 

--

 

--

 

--

 

  

 

  

 

  

 

  

 

  

 

  

 

Total

  

112

 

77.02

 

--

 

--

 

112

 

77.02

 

  

 

  

 

  

 

  

 

  

 

  

 

___________________________

(1)  We had one producing natural gas well until December of 2003, when it was temporarily shut-in.  Our remaining production of natural gas comes from wells which we classify as oil wells, due to the fact that the principal production from such wells is oil.

 

Drilling Activity


In the past three years we have focused our attention primarily on property acquisitions, and not on exploitation of our properties.  However, in 2001 we participated in the drilling of two gross wells in Oklahoma (each a 0.7 net well). One well was completed as a producing well, and the other was plugged and abandoned as a dry hole. In 2002 we participated in the drilling of one gross well (0.8 net well) in Kansas, which was completed as a producing well.  In 2003 we participated in drilling one gross well (0.08 net well) in Kansas, which was plugged and abandoned as a dry hole.

 

Cost Information


We conduct our oil and natural gas activities entirely in the United States. Our average production costs, per Boe, were $7.81 in 2001, $8.82 in 2002 and $8.94 in 2003. capitalized incurred costs in our oil and natural gas producing activities are shown below.





 

  

Years Ended December 31

 

  

2001

 

 

2002

 

 

2003

Acquisition of proved properties

  

$

1,032,786

  

$

2,659,832

  

$

2,470,821

gas Acquisition of unproved properties

  

 

--

   

--

   

147,000

Exploration costs

  

 

--

   

--

   

326,410

Development costs

  

551,859

   

579,153

   

849,864

Acquisition of support and office equipment

  

--

   

29,388

   

--

Asset retirement costs recognized upon adoption of SFAS No. 143

  

--

   

--

   

221,218

 

  

          

Total Costs Incurred

  

$

1,584,645

  

$

3,268,373

  

$

4,015,313



13










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, 2000

  

--

  

478,263

Purchases of minerals in place

  

493,649

  

1,636,959

Extensions and discoveries

  

--

  

843,512

Production

  

(16,211)

  

(5,590)

Revisions of previous estimates

  

17,385

  

7,229

 

  

  

 

 

Balance, December 31, 2001

  

494,823

  

2,960,373

Purchases of minerals in place

  

5,465,906

  

1,676,706

Extensions and discoveries

  

--

  

--

Production

  

(58,717)

  

(46,819)

Revisions of previous estimates

  

80,674

  

(1,402,503)

 

  

    

Balance, December 31, 2002

  

5,982,686

  

3,187,757

Purchases of minerals in place

  

3,175.357

  

570,924

Extensions and discoveries

  

18,066

  

229,626

Production

  

(117,646)

  

(67,329)

Revisions of previous estimates

  

(139,546)

  

(512,224)

 

  

    

Balance, December 31, 2003

  

8,918,917

  

3,408,754

 

  

  

 

 



14









Our proved oil and natural gas reserves are shown below.


 

  

As of December 31,

  

 

  

2001

  

2002

  

2003

  

Oil (Bbls):

  

 

  

 

  

 

  

Developed

  

142,371

 

750,464

 

1,580,521

  

Undeveloped

  

352,452

 

5,232,222

 

7,338,396

  

 

  

     

  

Total

  

494,823

 

5,982,686

 

8,918,917

  

 

  

 

  

 

  

 

  

Natural Gas (Mcf):

  

 

  

 

  

 

  

Developed

  

1,038,564

 

1,160,639

 

1,612,738

  

Undeveloped

  

1,921,809

 

2,027,118

 

1,796,016

  

 

  

     

  

Total

  

2,960,373

 

3,187,757

 

3,408,754

  

 

  

 

  

 

  

 

  

Total (Boe):

  

 

  

 

  

 

  

Developed

  

315,465

 

943,904

 

1,849,311

  

Undeveloped

  

672,754

 

5,570,076

 

7,637,732

  

 

  

     

  

Total

  

988,219

 

6,513,980

 

9,487,043

  


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.



15









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



   

December 31,

   

2002

  

2003

 

      

Future cash inflows

 

$

154,639,383

 

$

272,687,194

Future production and development costs

  

(42,401,610)

  

(87,622,591)

Future income tax expense

  

(36,580,859)

  

(60,917,690)

 

  


  


Future net cash flows

  

75,656,914

  

124,146,913

10% annual discount for estimated timing of cash flows

  

(33,180,087)

  

(62,335,966)

 

  


  


Standardized measure of discounted future net cash flows

 

$

42,476,827

 

$

61,810,947


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,

 

  

2002

 

2003

 

  

Beginning of the year

  

$

5,203,372

 

$

42,476,827

Purchase of minerals in place

  

 

48,956,314

 

 

21,333,720

Extensions, discoveries and improved recovery, less related costs

  

 

--

 

 

691,469

Development costs incurred during the year

  

 

215,433

 

 

320,102

Sales of oil and gas produced, net of production costs

  

 

(1,057,366)

  

(2,302,405)

Accretion of discount

  

 

3,525,683

  

4,496,888

Net changes in prices and production costs

  

 

6,456,827

  

11,873,094

Net change in estimated future development costs

  

 

(142,491)

  

42,383

Revisions of previous quantity estimates

  

 

(2,497,666)

  

(24,513)

Revision in estimated timing of cash flows

  

 

--

  

(7,110,749)

Net change in income taxes

  

(18,183,279)

  

(9,985,869)

 

  

 


 

 


End of the Year

  

$

42,476,827

 

$

61,810,947


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 13,353 gross (9,784 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, 2003, we owned interests in



16










approximately 2,576 gross undeveloped acres (2,074 net).  While our short-term business strategy is to continue to acquire properties with both existing cash flow from production and future development potential, our intermediate and long-term business plan includes the further exploitation of our properties through additional drilling activities. After we have expanded our portfolio of producing properties, we anticipate financing these future exploitation activities from the cash flow generated by production.  Our current strategy is to attempt to acquire approximately $8 million to $10 million in additional properties to achieve “critical mass”.  We believe the cash flow from existing production on our current properties and these new acquisitions will enable us to undertake the further development and exploitation in a prudent manner.  See “Proposed Acquisition Activity” below.  


We anticipate that we will soon seek additional capital as a source of a portion of the funding of this acquisition strategy.  If we are not successful in raising the anticipated funds in this manner, we may not be able to secure sufficient capital (from borrowings or otherwise) to acquire $8 million to $10 million in additional properties.  This could lead us to alter our current business strategy (focusing on acquisitions), and instead result in our determination that we should concentrate on the exploitation and further development of our existing properties.  Such a determination could also significantly alter our business plan regarding the source of financing for such development activities (because our cash flow from our current production would not be sufficient to undertake the level of development we currently anticipate).  In such event, it is possible that we would have to significantly decrease the level of exploration activities that we would otherwise undertake.


Pursuing Profitable Acquisitions.    We have pursued and intend to continue to pursue 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. From August 2000 through December 31, 2003, we acquired 10 leases at an aggregate acquisition and enhancement cost of approximately $7.9 million, representing approximately 9.5 million Boe of proved reserves (at an average cost of $0.83 per Boe).


Focusing on High Return Operated Properties.    We have historically acquired operated properties that meet or exceed our rate of return criteria. For acquisitions of properties with additional development, exploitation and exploration potential, our focus has been on acquiring properties we can operate so that we can better control the timing and implementation of capital spending. We intend to continue to acquire both operated and non-operated interests to the extent they meet our return criteria and further our growth strategy.


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, 2003, our lease operating expense per Boe averaged $8.94 and general and administrative costs averaged $4.34 per Boe produced.


Other Properties and Commitments


The Company currently leases its principal executive offices in Tulsa, Oklahoma.  The lease is for approximately 2,352 square feet of office space, at an annual rental of $20,400.  The lease expires on December 31, 2005.  The current facilities are believed adequate for the current operations of Arena.



17









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


No matter was submitted to a vote of security holders, through solicitation of proxies or otherwise, during the period from October 1, 2003, through December 31, 2003




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 two years.  



Period

High Sale or Bid

Low Sale or Bid

   

1st Quarter 2002

$2.65

$2.40

2nd Quarter 2002

 4.00

 2.40

3rd Quarter 2002

 4.25

 3.99

4th Quarter 2002

 4.60

 4.00

 



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 (through March 12)

$6.80

$5.85



Record Holders


As of January 20, 2004, there are approximately 647 holders of record of our common stock.  Approximately 34%, or 2,430,200 shares of the 7,167,097 shares issued and outstanding as of such date are held by management or affiliated parties.



18









Dividend Policy


We have not paid any dividends on our common stock during the last two 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.  Information regarding this plan and the options that have been granted under this plan may be found in the Annual Report under Part III, Items 10 and 11.  


Recent Sales of Unregistered Securities


In October 2003, we issued 25,000 shares of common stock valued at $5.64 per share, or $141,000, as compensation to a consultant utilized in connection with our acquisition of the North Benson Queen Unit in Eddy County, New Mexico. The 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 person 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 this transaction.


In October 2003, we also issued an additional 7,000 shares of common stock valued at $5.65 per share, or $39,550, as compensation to a consultant utilized in connection with our acquisition of the West San Andres Unit in Yoakum County, Texas. The 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 person 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 this transaction.


During October 2003, we issued 8,000 shares of our common stock upon the exercise of warrants, at $1.75 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 person 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 this transaction.

 


19










Issuer Repurchases


We did not make any repurchases of our equity securities during the quarter ending December 31, 2003.


Item 6:

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 three years, we have emphasized the acquisition of properties that provided current production and significant upside potential through further development.


We have increased our reserves significantly by investing $3 million in acquisitions and enhancements in 2003, following total capital expenditures of approximately $3.2 million in 2002 and approximately $1.6 million in 2001. In addition, our management technical staff has identified significant additional reserves following our acquisitions.


Our capital budget for 2004 is approximately $10 million, which will be utilized to acquire properties.  We anticipate that we will soon seek additional capital as a source of a portion of this capital budget..  The remainder of the funds for our acquisition program will come from a portion of our anticipated cash flow from operations and, possibly, a portion of the amount we can draw under our available credit facility. We anticipate this amount will be used almost exclusively for the acquisition of additional reserves in 2004.  However, our strategy could change if we are unable to find suitable properties at a price we believe satisfies our acquisition strategy, or in the event we decide not to seek additional capital (or are unsuccessful in such endeavor)and we are unable to obtain alternate sources of financing for such acquisition activities.  In such an event, it is possible that we could deviate from our current business plan, and begin the exploitation and further development of our existing properties by spending a portion of our capital budget on drilling activities.  In this event, the amount of development activities that we would undertake could be significantly less than the development activities that we anticipate conducting assuming this offering (and the related acquisition program) is successful.


We have historically acquired operated properties that meet or exceed our rate of return criteria. Because our strategy is to acquire producing properties with additional development, exploitation and exploration potential, our focus has been on acquiring operated properties so that we can better control the timing and implementation of capital spending. In some instances, we have been able to acquire non-operated property interests at attractive rates of return that provided a foothold in a new area of interest or complemented our existing operations. We intend to continue to acquire both operated and non-operated interests to the extent we believe they meet our return criteria. 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.


20











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.


Results of Operations


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


 

  

Years Ended December 31,

 

  

2001

  

2002

  

2003

Net production:

  

        

Oil (Bbls)

  

 

12,895

  

59,468

  

117,646

Natural gas (Mcf)

  

 

4,776

  

47,985

  

65,417

          

Net sales:

  

 

       

Oil

  

 

$     302,424

  

$     1,532,045

  

$     3,418,480

Natural gas

  

 

9,309

  

124,992

  

246,997

          

Average sales price:

  

 

       

Oil (per Bbl)

  

 

$         22.36

  

$            25.76

  

$            29.06

Natural gas (per Mcf)

  

 

1.79

  

2.60

  

3.78

          

Production costs and expenses:

  

 

       

Lease operating expenses

  

 

$     106,927

  

$         94,863

  

$     1,149,136

Production taxes

  

 

14,797

  

117,164

  

269,563

Depreciation, depletion and amortization expense

  

 

44,148

  

128,847

  

338,157

General and administrative expenses

  

 

127,696

  

248,018

  

557,576


Year Ended December 31, 2003 Compared to Year Ended December 31, 2002


Oil and natural gas sales.    Oil and natural gas sales revenue increased approximately $2 million to $3.66 million in 2003. Oil sales increased $1.89 million and natural gas sales increased $122,000. The oil sales increase was caused by a sales volume increase of 58,178 barrels in 2003, and a 13% increase in the average realized per barrel oil price from $25.76 in 2002 to $29.06 in 2003.  The natural gas sales increase was caused by a sales volume increase of 17,432 Mcf in 2003 and a 45% increase in the average realized natural gas price per Mcf from $2.60 in 2002 to $3.78 in 2003. The volume increase for crude oil and natural gas primarily resulted from $3 million of capital expenditures during 2003.



21










Lease operating expenses.    Our lease operating expenses increased from $594,863 or $8.82 per Boe in 2002 to $1,149,136 or $8.94 per Boe in 2003. This increase was a result of higher operating costs on properties acquired in 2003.  While it is possible that this increase will continue in the future as we acquire additional properties, because each property is individual in its characteristics, at this time, apart from normal increases associated with inflation in general, we cannot specifically identify this increase to be a trend.


Production taxes.    Production taxes as a percentage of oil and natural gas sales were 7% during 2002 and remained steady at 7% in 2003.  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 $210,310 to $338,157 in 2003. The increase was a result of an increase in the average depreciation, depletion and amortization rate from $1.84 per Boe during 2002 to $2.55 per Boe during 2003. 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 $309,558 to $557,576 during 2003. This increase was primarily related to increases in compensation expense associated with an increase in personnel required to administer our growth (specifically, the addition of our in-house engineer), listing fees of $56,625 paid to the American Stock Exchange, $61,280 in fees paid to a stock research analyst, fees related to obtaining our credit facility and letters of credit and directors fees.


Interest expense.    Interest expense increased $22,875 to $38,798 in 2003. The increase was due to our debt being outstanding for the entire year in 2003, as opposed to being outstanding for a partial year in 2002.


Income tax expense.    Our effective tax rate was 37% during 2003 and 32% during 2002. The effective rate was higher during 2003 due to having more income subject to income tax, higher state income tax and no benefit of operating loss carry forwards in 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 $19,272 decrease in net income during 2003.


Net income.    Net income increased from $402,694 for 2002 before preferred stock dividends, to $824,322 for 2003. 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 lease operating expense, tax expense and general and administrative expenses due to our growth.



22










Year Ended December 31, 2002 Compared to Year Ended December 31, 2001


Oil and natural gas sales.    Oil and natural gas sales revenue increased approximately $1.35 million to $1.66 million in 2002. Oil sales increased $1.2 million and natural gas sales increased $116,000. The oil sales increase was caused by a sales volume increase of 46,573 barrels in 2002 and a 15% increase in the average realized oil price from $22.36 in 2001 to $25.76 in 2002. The natural gas sales increase was caused by a sales volume increase of 43,209 Mcf in 2002 and a 45% increase in the average realized natural gas price from $1.79 per Mcf in 2001 to $2.60 in 2002.The volume increase for oil and natural gas was due to $3.2 million of capital expenditures during 2001 and 2002.  


Lease operating expenses.    Our lease operating expenses per Boe increased from $106,927 or $7.81 per Boe in 2001 to $594,863 or $8.82 per Boe in 2002. The increase resulted primarily from higher operating costs associated with properties acquired in 2002.


Production taxes.    Production taxes as a percentage of oil and natural gas sales were 7% in 2002 and 5% in 2001. The increase in the effective rate resulted from increased operations in the state of Oklahoma, where production tax rates are higher.


Depreciation, depletion and amortization.    Depreciation, depletion and amortization expense increased by $83,699 from $44,148 in 2001 to $127,847 in 2002.  The increase was a result of increasing sales volumes, though partially offset by a decreased depletion rate per Boe from $2.57 in 2001 to $1.84 in 2002.


General and administrative expenses.    General and administrative expenses increased 94% or $120,322 from $127,696 (which includes $8,000 in non-cash services contributed by majority shareholders) in 2001 to $248,018 in 2002. This increase was related to increases in compensation expense associated with increased personnel (specifically, the hiring of an administrative assistant), our executive officers receiving a salary for the entire year in 2002, as opposed to four months in 2001 (since our Chairman and President voluntarily deferred receiving compensation until September 2001, following our initial public offering, and our chief financial officer was hired in September of 2001).


Interest expense.     Interest expense increased to $17,425 in 2002 from $0 in 2001. The increase was due to higher average debt levels in 2002 to fund our growth.


Income tax expense.    Our effective tax rate before tax credits was 32% in 2002 compared to 0% in 2001, when we had no taxable income.


Net income (loss).    Our net loss attributable to common stockholders increased from $(44,927) in 2001 to $(395,324) in 2002. The primary reasons were a $734,496 increase in preferred stock dividends and an $811,749 increase in expenses, offset by a $1.3 million increase in revenues. The increase in preferred stock dividends was caused by more of our preferred stock being outstanding for a longer part of the year.  The expense increase was caused by higher operating expenses from additional leases, higher production tax and depreciation, depletion and amortization from higher production, and higher general and administrative expense related to increases in compensation expenses associated with increased personnel to administer our growth. The revenue increase was caused by higher production volumes and an increase in oil and natural gas prices between years 2001 and 2002.



23










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, and private equity offerings of our stock and warrants.


Credit Facility.    In February 2003 we established a $10,000,000 revolving credit facility with an initial borrowing base of $2,000,000.  In December 2003, we entered into an agreement that increased the facility to $20,000,000, with an increased borrowing base of $4,000,000. The borrowing base is based on the collateral value of proved reserves and is subject to redetermination semiannually, based on both commodity prices of oil and natural gas, and our estimated proved reserves. The credit facility, as amended in December 2003, provides for interest at a floating rate equal to the JP Morgan Chase prime rate plus 1%, with interest payable monthly, and annual fees of ¼ of 1% of the unused portion of the borrowing base.  Any amounts borrowed will be due December 31, 2005. The credit facility has covenants that restrict the payment of cash dividends, borrowings, sale of assets, loans to others, investments, merger activity, liens and certain other transactions without the prior consent of the lender. The facility also requires us to maintain a 5-to-1 ratio of income before interest, taxes, depreciation, depletion and amortization to interest expense, a current ratio of 1-to-1, and a tangible net worth of $6 million. The credit agreement is secured by a first lien on substantially all of our assets. In addition, our loans from two officers which were outstanding prior to this facility are subordinated to the debt evidenced by the credit facility.  As of December 31, 2003, no amounts are owed under this credit facility.  


Cash Flows.    Our primary sources of cash have been cash flows from operations, and equity offerings. During the three years ended December 31, 2003, we generated $2,307,721 from operating activities, financed $5,393,954 through proceeds from the sale of stock and warrants, and $400,000 from debt obligations owed to two officers, for a total of $8,101,675. We primarily used this cash generation to fund our capital expenditures aggregating $6,905,508 over the three years. At December 31, 2003, we had $1,076,676 of cash and $1,268,888 of working capital compared to December 31, 2002 when our cash position was $796,915 and working capital was $937,120.


We continually evaluate our capital needs and compare them to our capital resources. Our budgeted capital expenditures for 2004 are $10,000,000 for acquisitions to expand our property base. We expect to fund these expenditures from cash on hand, additional capital that we anticipate seeking, internally generated cash flow during the year 2004, and from borrowings under our credit facility, if required. In the event we are not successful in raising the anticipated funds from our proposed securities offering, we nevertheless believe capital expenditures of approximately $10,000,000 could be financed through cash on hand, additional borrowings under our credit facility or otherwise (including financing on a property-by-property basis). 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.


If we are not successful in obtaining funding from the sources above to finance our acquisition program, we anticipate that we would instead seek to acquire a smaller number of producing properties and/or initiate further development of our existing properties.  This development would be funded by internally generated cash flow and from borrowings under our credit facility.  If the funding is limited to these sources, our anticipated development activities would be more limited than anticipated under our present business plan (which calls for such activities to be substantially funded from a broader base of producing properties acquired through our acquisition program).


Schedule of Contractual Obligations.    The following table summarizes our future estimated principal and minimum debt and lease payments for periods subsequent to December 31, 2003.



24










Year

    

Long-Term Debt

    

Lease Obligation

    

Total Cash Obligation

2004

    

$

--  

    

$

20,400

    

$

20,400

2005

    

$

400,000  

    

$

20,400

    

$

420,400

2006

    

$

--

    

$

--

    

$

--

Total

    

$

400,000

    

$

40,800

    

$

440,800


Off-Balance Sheet Financing Arrangements


As of December 31, 2003 we had no off-balance sheet financing arrangements.


New Accounting Policies


In June 2001, the Financial Accounting Standards Board, or the FASB, issued Statement of Financial Accounting Standards, or SFAS, No. 141, “Business Combinations,” which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets,” which discontinues the practice of amortizing goodwill and indefinite-lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. The adoption of SFAS No. 142 has had no effect on our financial statements, as the Company has not recognized any intangible assets, since the fair market value of all assets acquired has exceeded the purchase price.


In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associates with Exit or Disposal Activities.” This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (“EITF”) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. We do not believe that adoption of this Statement will have a material impact on our financial statements.


In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. The interpretation requires that a liability measured at fair value be recognized for guarantees. The Company has not provided any guarantees and therefore the adoption of the interpretation had no impact on the Company’s financial statements.


In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure. Under the requirements of this statement, the Company has disclosed the effects on reported net income of the Company’s accounting policy with respect to stock-based employee compensation.  See Note 7 to our financial statements included as a part of this Annual Report.



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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).


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 August 2002. 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.


26










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. Estimates prepared by others may be higher or lower than our estimates. 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.



27










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


We have not experienced any significant increased costs during 2002 and 2003 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. 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. While we do not currently expect business costs to materially increase, continued high prices for oil and natural gas could result in increases in the cost of material, services and personnel.


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


In the event we draw under our current credit facility that has a floating interest rate, interest rate changes will impact future results of operations and cash flows.



Item 7:

Financial Statements


The financial statements and supplementary data required by this item are included at page 40.



Item 8:

Changes in and Disagreements with Accountants And Accounting and Financial Disclosure


None.



Item 8A:

Controls and Procedures


We maintain controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Based upon their evaluation of those controls and procedures performed within 90 days of the filing date of this report, the chief executive officer and the principal financial officer of the Company concluded that our disclosure controls and procedures were adequate.



28










We made no significant changes in its internal controls or in other factors that could significantly affect these controls subsequent to the date of the evaluation of those controls by the chief executive officer and principal financial officer.


PART III


Item 9:

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, 2003:


Name

 

Age

 

Position

Lloyd T. Rochford

  

57

  

President and Chief Executive Officer and Director

Stanley M. McCabe

  

71

  

Chairman of the Board of Directors, Secretary and Treasurer

William R. Broaddrick

  

26

  

Vice President and Chief Financial Officer

Charles M. Crawford

  

51

  

Director

Chris V. Kemendo, Jr.

  

82

  

Director

Clayton E. Woodrum

  

63

  

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 July 2003, with the exception of Mr. Woodrum.  Mr. Woodrum was appointed in August 2003 by the Board of Directors to fill a vacancy created upon the resignation of a director.


Messrs. Rochford, McCabe and Crawford have served as directors since our inception in August 2000.  Mr. KemendoKemendo was first elected to the Board of Directors in February 2003.


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


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

 

Mr. Rochford, 57, 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 is 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. Since July, 1997, Mr. Rochford has primarily devoted his time and efforts to individual oil and gas acquisition and development prior to his commitment to participate in Arena Resources. 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.



29











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


Mr. McCabe, 71, 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. Since January, 1997, Mr. McCabe has been involved as an independent investor and developer of oil and natural gas properties. 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, 26, 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, 51, 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, 82, has from 1989 to present acted as an independent financial business and accounting consultant to various clients. Mr. Kemendo is currently the Chairman of our audit committee. 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, 63, is a Certified Public Accountant and has, from 1984 to present, been a principal shareholder in the accounting firm of Woodrum, Kemendo & Cuite, P.C., and has been an owner of Computer Data Litigation Services, LLC and First Capital Management, LLC.  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 & Cuite, P.C., Ben Kemendo, is the son of Chris Kemendo, Jr.



30










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 2004 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. Kemendo 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. Each of Messrs. Kemendo and Woodrum further qualifies as “independent” in accordance with the applicable regulations adopted by the SEC and American Stock Exchange.


We currently do not have a separate compensation committee.  However, 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 a majority of the independent directors serving on the Board.  Compensation for all other officers is determined, or recommended to the Board for determination, by a majority of the independent directors.


We currently do not have a nominating committee.


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.  No director receives a salary as a director.


Compensation Committee Interlocks and Insider Participation


As noted above, we currently do not have a compensation committee. As a result, the majority of our independent members of our board, consisting of Messrs. Crawford, Kemendo and Woodrum, are responsible for fixing the compensation to be paid to our executive officers. 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.



31










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


The Company has adopted a code of ethics that applies to its 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 10:

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

($)

  


Securities Underlying Options(2)

Lloyd T. Rochford

President and Chief Executive Officer

2001

$24,500

  

--

  

--

 

2002

$36,000

--

--

 

2003

$36,000

--

$229,742

     

Stanley M. McCabe

Chairman of the Board

2001

$24,500

  

--

  

--

 

2002

$36,000

--

--

 

2003

$36,000

--

$229,742

     

William R. Broaddrick

Vice President, Chief Financial Officer

2001

$16,334

  

$3,000

  

--

 

2002

$45,000

$6,000

--

 

2003

$47,927

--

$459,484

____________________________________

(1)  Mr. Broaddrick’s salary for 2003 reflects a raise that occurred in mid-year to increase his annual salary to $50,000.  There are no current plans to change any officers’ salary from their level at DecemberDecember31, 2003.

(2)  The fair value of the options is 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 at December 31, 2003 was 4.2 years.


32












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. 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 1,000,000 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. All of the shares available for grant under the plan have been reserved for issuance pursuant to options granted during 2003, as shown in the table below.



Name


Number of Securities Underlying Options/SARs Granted

Percent of Total Options/SARs Granted to Employees in Fiscal Year


Exercise Of Base Price ($/Sh)

Market Price per Share on Date of Grant

Expiration Date

      

Lloyd T. Rochford

125,000

12.5%

$3.70

$4.41

6/1/08

Stanley M. McCabe

125,000

12.5%

$3.70

$4.41

6/1/08

William R. Broaddrick

250,000

25.0%

$3.70

$4.41

6/1/08

Charles M. Crawford

50,000

5.0%

$3.70

$4.41

6/1/08

Chris V. Kemendo, Jr.

50,000

5.0%

$3.70

$4.41

6/1/08

Clayton E. Woodrum

50,000

5.0%

$4.80

$5.65

10/17/08

Phillip W. Terry

250,000

25.0%

$3.70

$4.41

6/1/08

Raymond H. Estep

100,000

10.0%

$3.70

$4.41

6/1/08

      


Each of the options identified above vests at the rate of 20% each year over five years beginning one year from the date of grant.  All of the options identified above, with the exception of options granted to Mr. Woodrum, were issued on April 1, 2003.  Mr. Woodrum’s options were granted on August 18, 2003. Therefore, no options were capable of being exercised during our fiscal year ending December 31, 2003.  The exercise price of each option was 85% of the closing market price of our common stock on the date the option was issued.  The options for 50,000 shares granted to Mr. Woodrum, were originally granted to a former director on April 1, 2003; however, upon such director’s resignation, in accordance with the terms of the options, those options were forfeited.  Mr. Woodrum’s options were granted in connection with his appointment to fill the vacant board position.


33











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, 2003 and the exercise price of the options.


Name

Shares Acquired on Exercise

Value Realized ($)

Number of Unexercised Securities Underlying Options/SARs at FY-End (#)

Exercisable/

Unexercisable

Value of Unexercisable In-The-Money Options/SARs at FY-End ($) Exercisable/

Unexercisable

     

Lloyd T. Rochford

0

0

0/125,000

$0/$291,250

Stanley M. McCabe

0

0

0/125/000

$0/$291,250

William R. Broaddrick

0

0

0/250,000

$0/$582,500

Charles M. Crawford

0

0

0/50,000

$0/$116,500

Chris V. Kemendo, Jr.

0

0

0/50,000

$0/$116,500

Clayton E. Woodrum

0

0

0/50,000

$0/$61,500

Phillip W. Terry

0

0

0/250,000

$0/$582,500

Raymond H. Estep

0

0

0/100,000

$0/$233,000

     


The following table sets forth information concerning our executive stock option plan as of December 31, 2003.


  

Number of securities to be issued upon exercise of outstanding options

 

Weighted –average exercise price of outstanding options

 

Number of securities remaining available for future issuance under equity compensation plans (excluding securities in column (a))

  

(a)

 

(b)

 

(c)

Equity compensation plans approved by security holders

 

1,000,000

 

$3.76

 

-0-

       

Equity compensation plans not approved by security holders

 

--

 

--

 

--

       

Total

 

1,000,000

 

$3.76

 

1,000,000



34










Item 11:

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


The following table sets forth, as of the date hereof, 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 table also reflects what their ownership will be assuming completion of the sale of all shares in this offering (without taking into account the exercise of any warrants).  The mailing address for each of the persons indicated is our corporate headquarters.


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


 

  

Shares of Common

Stock Beneficially

Owned 

 

Name

  

Number

 

  

Percent

 

Lloyd T. Rochford

  

1,312,600 (1)

 

  

18.3%

 

 

  

  

  

 

 

Stanley M. McCabe

  

1,163,000 (2)

 

  

16.2%

 

 

  

  

  

 

 

William R. Broaddrick

  

54,500 (3)

 

  

*

 

 

  

  

  

 

 

Charles M. Crawford

  

10,000 (4)

 

  

*

 

 

  

  

  

 

 

Chris V. Kemendo, Jr.

  

10,100 (5)

 

  

*

 

 

  

  

  

 

 

Clayton E. Woodrum

  

--

 

  

*

 

All directors and executive officers as a group (6 persons)

  

2,550,200 (6)

  

35.6%

 



(1)

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

(2)

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

(3)

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

(4)

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

(5)

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

(6)

Includes 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  7,163,097 shares of our common stock outstanding as of March 10, 2004,

.


35









Item 12:

Certain Relationships and Related Transactions


The initial capital assets that were contributed to us were provided by Messrs. Rochford and McCabe.  In contributing these assets to us in September 2000, no independent determination was made regarding the value of the oil and gas properties and related interests contributed in exchange for stock.  In exchange for the initial 1,300,000 shares of common stock issued to each of Messrs. Rochford and McCabe, each contributed $33,695 in cash and a carried working interest obligation with future development costs estimated by an independent oil and gas engineer of approximately $134,000. Of the cash contributed, $61,174 was used to acquire our three initial leases.  The estimated future development costs were accounted for as a receivable from Messrs. Rochford and McCabe.  Total actual costs incurred by them in relation to the carried working interest were $121,274.  The difference of $12,726 was charged against additional paid in capital.


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, 2005.  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 13:

Exhibits and Reports on Form 8-K


Reports on Form 8-K:


None


Exhibit Index:


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 December 31, 2003, among Arena Resources, Inc. and Bank of Oklahoma, N.A.


10.2

Form of Stock Option Subscription Agreements (ii)


23

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


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 Resource, Inc.’s Form SB-1 filed September 20, 2000 (SEC File No. 333-46164).


(ii)  Incorporated by reference to Arena Resource, Inc.’s Form 10-QSB, filed May 15, 2003.




36










Item 14:

Principal Accountant Fees and Services


Hansen, Barnett & Maxwell served as our independent accountants for the years ended December 31, 2002 and 2003, and is expected to serve in that capacity for the current year. Principal accounting fees for professional services rendered for us by Hansen, Barnett & Maxwell for the years ended December 31, 2002 and 2003 are summarized as follows:


   

2002(1)

 

2003(1)

Audit

  

$12,265

 

 $ 29,617

Audit related

 

2,083

 

        888

Tax

  

747

 

     1,052

All other

  

   -  

 

          -   

Total

  

 $ 15,095

 

 $ 31,557


1 The aggregate fees included in “Audit” are fees billed for the fiscal years for the audit of the Company’s annual financial statements, review of the financial statements and statutory and regulatory filings or engagements. The aggregate fees included in each of the other categories are for fees billed in the fiscal years.


Audit Fees. Audit fees were for professional services rendered in connection with audits and quarterly reviews of financial statements of the Company and review of and preparation of consents for this registration statement for filing with the Securities and Exchange Commission.


Audit Related Fees. Audit related fees were for consultations regarding financial accounting and reporting standards primarily related to acquisitions of oil and gas properties.


Tax Fees.  Tax fees related to services for tax compliance and consulting.


Audit Committee Pre-Approval Policies and Procedures.  At its regularly scheduled and special meetings, the Audit Committee of the Board of Directors, which is comprised of independent directors knowledgeable of financial reporting, considers and pre-approves any audit and non-audit services to be performed by the Company’s independent accountants.  The Audit Committee has the authority to grant pre-approvals of non-audit services. That procedure was put into place promptly after July 30, 2002, the effective date of the Sarbanes-Oxley Act of 2002.  At that time, the Audit Committee approved all non-audit services being performed at that time by the Company’s independent accountants and adopted its pre-approval policies and procedures as set forth above. From the date of that meeting, there were no non-audit services performed by the Company’s independent accountants that were not per-approved. Accordingly, the de minimus exception under Section 202 of the Sarbanes-Oxley Act of 2002 was applicable.


The Company’s Audit Committee has considered whether the provision of the non-audit services provided by Hansen, Barnett & Maxwell is compatible with maintaining the accountant’s independence.




37










SIGNATURES


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



ARENA RESOURCES, INC.




By:

/s/  Lloyd T. Rochford


Mr. Lloyd T. Rochford, President,

Chief Executive Officer


Date:  March 18, 2004



By:

/s/  Stanley McCabe


Mr. Stanley McCabe

Treasurer, Secretary


Date:

March 18, 2004




By:

/s/  William R. Broaddrick


Mr. William R. Broaddrick

Chief Financial Officer


Date:

March 18, 2004


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, President,

Chief Executive Officer


Date:  March 18, 2004



By:

/s/  Stanley McCabe


Mr. Stanley McCabe

Treasurer, Secretary


Date:

March 18, 2004




38









By:


Mr. Charles Crawford

Director


Date:

March 18, 2003




By:

/s/  Chris V. Kemendo, Jr.


Mr. Chris V. Kemendo, Jr.

Director


Date:

March 18, 2003



By:

/s/  Clayton E. Woodrum


Mr. Clayton E. Woodrum

Director


Date:

March 18, 2004




39











ARENA RESOURCES, INC.


INDEX TO FINANCIAL STATEMENTS



Page


Report of Independent Certified Public Accountants

41


Balance Sheets - December 31, 2003 and 2002

42


Statements of Operations for the Years Ended December 31, 2003 and 2002

43


Statements of Stockholders’ Equity for the Years Ended December 31, 2002 and 2003

44


Statements of Cash Flows for the Years Ended December 31, 2003 and 2002

45


Notes to Financial Statements

46


Supplemental Information on Oil and Gas Producing Activities

58



40










HANSEN, BARNETT & MAXWELL

A Professional Corporation

CERTIFIED PUBLIC ACCOUNTANTS

5 Triad Center, Suite 750

Salt Lake City, UT 84180-1128

Phone: (801) 532-2200

Fax: (801) 532-7944

www.hbmcpas.com






REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS



To the Board of Directors and the Stockholders

Arena Resources, Inc.


We have audited the accompanying balance sheets of Arena Resources, Inc. as of December 31, 2003 and 2002, and the related statements of operations, stockholders' equity, and cash flows for the years then ended. 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 auditing standards generally accepted in the United States of America. 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. An audit also includes 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, 2003 and 2002, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.



HANSEN, BARNETT & MAXWELL

Salt Lake City, Utah

January 20, 2004



41









ARENA RESOURCES, INC.

BALANCE SHEETS



December 31,

 

 2003

 

2002

 

 

 

 

 

ASSETS

 

 

 

 

Current Assets

 

 

 

 

Cash and cash equivalents

 

 $            1,076,676

 

 $           796,915

Account receivable

 

                  388,910

 

              269,436

Short-term investments

 

                    25,234

 

                       -   

Common stock subscription receivable

 

                            -   

 

              157,500

Prepaid expenses

 

                    28,935

 

                  1,128

  

 

 

 

Total Current Assets

 

               1,519,755

 

           1,224,979

 

 

 

 

 

Property and Equipment, using full cost accounting

 

 

 

 

Oil and gas properties subject to amortization

 

               8,463,400

 

           4,884,804

Drilling advances

 

                  351,000

 

                       -   

Support equipment

 

                    48,480

 

                21,794

Office equipment

 

                    18,978

 

                14,672

Total Property and Equipment

 

               8,881,858

 

           4,921,270

Less:  Accumulated depreciation and amortization

 

                (513,754)

 

            (172,258)

  

 

 

 

Net Property and Equipment

 

               8,368,104

 

           4,749,012

 

 

 

 

 

Deferred Offering Costs

 

                  130,872

 

                       -   

 

 

 

 

 

Long-Term Deposits

 

                            -   

 

                76,502

 

 

 

 

 

Total Assets

 

 $          10,018,731

 

 $        6,050,493

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS' EQUITY

 

 

 

 

Current Liabilities

 

 

 

 

Accounts payable

 

 $               229,522

 

 $           173,174

Accrued liabilities

 

                    18,440

 

                       -   

Put option

 

                      2,905

 

                       -   

Accrued preferred dividends

 

                            -   

 

              114,685

 

 

 

 

 

Total Current Liabilities

 

                  250,867

 

              287,859

 

 

 

 

 

Long-Term Liabilities

 

 

 

 

Put option

 

                            -   

 

                50,604

Notes payable to officers

 

                  400,000

 

              400,000

Asset retirement liability

 

                  607,200

 

                       -   

Deferred income taxes

 

                  671,765

 

              187,193

 

 

 

 

 

Total Long-Term Liabilities

 

               1,678,965

 

              637,797

 

 

 

 

 

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;

 

 

 

 

  7,162,097 shares and 6,282,056 shares outstanding, respectively

 

                      7,162

 

                  6,282

Additional paid-in capital

 

               6,994,925

 

           5,287,189

 Options and warrants outstanding

 

                  813,164

 

              382,040

Retained earnings (deficit)

 

                  273,648

 

            (550,674)

 

 

 

 

 

Total Stockholders' Equity

 

               8,088,899

 

           5,124,837

 

 

 

 

 

Total Liabilities and Stockholders' Equity

 

 $          10,018,731

 

 $        6,050,493

 

 

 

 

 



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


42






ARENA RESOURCES, INC.

STATEMENTS OF OPERATIONS



For the Years Ended December 31,

 

2003

 

2002

 

 

 

 

Oil and Gas Revenues

 

 

 $ 3,665,477

 

 $ 1,657,037

 

 

 

 

 

Costs and Operating Expenses

 

 

 

 

Oil and gas production costs

 

    1,149,136

 

       594,863

 

Oil and gas production taxes

 

       269,563

 

       117,164

 

Depreciation and amortization

 

       338,157

 

       127,847

 

General and administrative expense

 

       557,576

 

       248,018

 

 

 

 

Total Costs and Operating Expenses

 

    2,314,432

 

    1,087,892

 

 

 

 

 

 

 

Other Income (Expense)

 

 

 

Gain from change in fair value of put options

         47,699

 

         36,665

 

Accretion expense

 

       (32,212)

 

                 -   

 

Interest expense

 

 

       (38,798)

 

       (15,923)

 

 

 

 

 

Net Other Income (Expense)

 

       (23,311)

 

         20,742

 

 

 

 

Income Before Provision for Income Taxes and Cumulative

 

   Effect of  Change in Accounting Principle

    1,327,734

 

       589,887

 

 

 

 

Provision for Deferred Income Taxes

 

     (491,599)

 

     (187,193)

 

 

 

 

 

 

Income Before Cumulative Effect of Change in Accounting Principle

       836,135

 

       402,694

 

 

 

 

 

Cumulative Effect of Change in Accounting Principle

       (11,813)

 

                 -   

 

 

 

 

Net Income

 

       824,322

 

       402,694

 

 

 

 

 

Preferred Stock Dividends

 

                 -   

 

     (798,018)

 

 

 

 

Income (Loss) Attributable to Common Shares

 $    824,322

 

 $  (395,324)

 

 

 

 

 

Basic Income (Loss) Per Common Share

 

 

 

Before cumulative effect of change in accounting principle

 $          0.12

 

 $        (0.09)

 

Cumulative effect of change in accounting principle

                 -   

 

                 -   

 

Income (Loss) Attributable to Common Shares

 $          0.12

 

 $        (0.09)

 

 

 

 

 

 

 

Diluted Income (Loss) Per Common Share

 

 

Before cumulative effect of change in accounting principle

 $          0.12

 

 $        (0.09)

 

Cumulative effect of change in accounting principle

                 -   

 

                 -   

 

Income (Loss) Attributable to Common Shares

 $          0.12

 

 $        (0.09)

 

 

 

   


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


43






ARENA RESOURCES, INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2002 AND 2003


           

 Additional

 

 Options and

 

 Receivable

 

 Retained

 

 Total

   

 Preferred Stock

 

 Common Stock

 

 Paid-in

 

 Warrants

 

 from

 

 Earnings

 

 Stockholders'

 

 

 

 Shares

 

 Amount

 

 Shares

 

 Amount

 

 Capital

 

 Outstanding

 

 Shareholders

 

 (Deficit)

 

 Equity

 Balance, December 31, 2001

      857,573

 

 $ 1,274,021

 

  3,604,500

 

 $      3,605

 

 $    817,811

 

 $   103,600.00

 

 $      (5,733)

 

 $ (155,350)

 

 $       2,037,954

 Issuance for cash

   1,028,786

 

    1,214,582

 

               -   

 

               -   

 

       114,402

 

           254,889

 

                -   

 

               -   

 

          1,583,873

 Issuance for cash to a related party

                -   

 

                 -   

 

       70,000

 

              70

 

         88,130

 

                     -   

 

                -   

 

               -   

 

               88,200

 Issuance for property acquisitions

                -   

 

                 -   

 

     149,885

 

            150

 

       525,260

 

                     -   

 

                -   

 

               -   

 

             525,410

 Preferred stock beneficial conversion dividends

                -   

 

       114,402

 

               -   

 

               -   

 

                 -   

 

                     -   

 

                -   

 

    (114,402)

 

                       -   

 Preferred stock cash dividends accrued

                -   

 

                 -   

 

               -   

 

               -   

 

                 -   

 

                     -   

 

                -   

 

    (274,589)

 

           (274,589)

 Preferred stock dividends paid with common stock

                -   

 

                 -   

 

     199,526

 

            199

 

       408,828

 

                     -   

 

                -   

 

    (409,027)

 

                       -   

 Conversion of preferred stock to common stock

  (1,886,359)

 

  (2,603,005)

 

  1,886,359

 

         1,886

 

    2,601,119

 

                     -   

 

                -   

 

               -   

 

                       -   

 Issuance upon exercise of warrants

                -   

 

                 -   

 

       74,786

 

              75

 

       215,565

 

           (84,764)

 

                -   

 

               -   

 

             130,876

 Issuance for cash

                -   

 

                 -   

 

     286,000

 

            286

 

       493,535

 

           108,315

 

                -   

 

               -   

 

             602,136

 Issuance for services

                -   

 

                 -   

 

       11,000

 

              11

 

         22,539

 

                     -   

 

                -   

 

               -   

 

               22,550

 Collection of receivable from shareholder

                -   

 

                 -   

 

               -   

 

               -   

 

                 -   

 

                     -   

 

           5,733

 

               -   

 

                 5,733

 Net Income

                -   

 

                 -   

 

               -   

 

               -   

 

                 -   

 

                     -   

 

                -   

 

     402,694

 

             589,887

 Balance, December 31, 2002

                -   

 

                 -   

 

  6,282,056

 

         6,282

 

    5,287,189

 

           382,040

 

                -   

 

    (550,674)

 

          5,124,837

 Issuance for cash

                -   

 

                 -   

 

     790,294

 

            790

 

    1,274,256

 

           436,154

 

                -   

 

               -   

 

          1,711,200

 Issuance of warrants as commission for 2002 offering

                -   

 

                 -   

 

               -   

 

               -   

 

        (15,922)

 

             15,922

 

                -   

 

               -   

 

                       -   

 Cancellation of shares for extension of lock up

                -   

 

                 -   

 

          (500)

 

               -   

 

                 -   

 

                     -   

 

                -   

 

               -   

 

                       -   

 Issuance for services

                -   

 

                 -   

 

       13,847

 

              14

 

         75,026

 

                     -   

 

                -   

 

               -   

 

               75,040

 Warrant exercise

                -   

 

                 -   

 

       19,400

 

              19

 

         54,883

 

           (20,952)

 

                -   

 

               -   

 

               33,950

 Issuance in property acquisitions

                -   

 

                 -   

 

       57,000

 

              57

 

       319,493

 

                     -   

 

                -   

 

               -   

 

             319,550

 Net Income

                -   

 

                 -   

 

               -   

 

               -   

 

                 -   

 

                     -   

 

                -   

 

     824,322

 

             824,322

 Balance, December 31, 2003

                -   

 

 $              -   

 

  7,162,097

 

 $      7,162

 

 $ 6,994,925

 

 $        813,164

 

 $             -   

 

 $  273,648

 

 $       8,088,899

                    


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


44





ARENA RESOURCES, INC.

STATEMENTS OF CASH FLOWS



For the Years Ended December 31,

  

2003

 

2002

Cash Flows From Operating Activities

    
 

Net income

   

$    824,322

 

$   402,694

 

Adjustments to reconcile net income to net cash

    
 

provided by operating activities:

    
 

Shares issued for services

  

75,040

 

-

 

Depreciation and amortization

 

338,154

 

127,847

 

Services and use of office space contributed by officers

-

 

22,550

 

Interest capitalized on certificates of deposit

-

 

(1,502)

 

Gain from change in fair value of put option

 

(47,699)

 

(36,665)

 

Cumulative effect of change in accounting principle

11,813

 

-

 

Accretion of discounted liabilities

 

32,212

 

-

 

Changes in assets and liabilities:

    
 

Accounts receivable

  

(119,474)

 

(258,730)

 

Prepaid expenses

  

(27,807)

 

(222)

 

Accounts payable and accrued liabilities

 

74,790

 

127,583

 

Deferred income taxes

  

491,599

 

187,193

        
 

Net Cash Provided by Operating Activities

 

1,652,950

 

570,748

        

Cash Flows from Investing Activities

    
 

Purchase of oil and gas properties

 

(3,050,558)

 

(2,603,279)

 

Purchase of support and office equipment

 

(30,992)

 

(29,388)

 

Increase in long-term deposits

  

-

 

(25,000)

 

Maturity of long-term deposits

  

51,268

 

-

        
 

Net Cash Used in Investing Activities

 

(3,030,282)

 

(2,657,667)

        

Cash Flows From Financing Activities

    
 

Proceeds from issuance of common stock and warrants, net of offering costs

1,580,328

 

532,836

 

Proceeds from issuance of preferred stock, net of offering costs

-

 

1,589,606

 

Proceeds from warrant exercise

  

33,950

 

130,876

 

Collection of common stock subscription receivable

157,500

 

-

 

Proceeds from issuance of note payable

 

-

 

400,000

 

Payment on note payable

  

-

 

(18,000)

 

Payment of dividends to preferred stockholders

 

(114,685)

 

(196,048)

        
 

Net Cash Provided by Financing Activities

 

1,657,093

 

2,439,270

        

Net Increase in Cash and Cash Equivalents

 

279,761

 

352,351

        

Cash and Cash Equivalents, Beginning of Year

 

796,915

 

444,564

        

Cash and Cash Equivalents, End of Year

 

$ 1,076,676

 

$   796,915

        

Supplemental Cash Flows Information

    
 

Cash paid for interest

  

$      38,798

 

$     17,425

        

Non-Cash Investing and Financing Activities

    
 

Common stock issued for properties less call options granted

$    319,550

 

$   525,410

 

Asset retirement obligations incurred

 

559,488

 

-

 

Accrual of preferred stock dividends

 

-

 

274,589

 

Receivable from shareholders related to stock offerings

-

 

157,500

 

Preferred stock dividends paid with common stock

-

 

409,027

 

Beneficial conversion feature on convertible preferred stock

-

 

114,402

 

Value of put option included in cost to acquire properties

-

 

87,269

        


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


45




ARENA RESOURCES, INC.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2003 AND 2002





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 Equivalents and Short-term investments –Cash and cash equivalents include investments in highly-liquid debt instruments with original maturities of three months or less. The Company has deposits with a bank that are $976,676 in excess of federally insured limits at December 31, 2003. Short-term investments consist of certificates of deposit totaling $25,234 which are assigned as collateral under standby letters of credit.


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 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.  Depletion and amortization expense for the year ended December 31, 2003, was $328,207, based on depletion at the rate of $2.55 per barrel-of-oil-equivalent and for the year ended December 31, 2002, was $124,391, based on depletion at the rate of $1.84 per barrel-of-oil-equivalent.


In addition, capitalized costs are subject to a “ceiling test,” which limits such costs to the aggregate of the “estimated present value,” discounted at a 10-percent interest rate of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties.


Support and Office Equipment – Depreciation of support and office equipment is computed using the straight-line method over the estimated useful life of the assets which is currently seven years.  Depreciation expense was $9,950 and $3,456 for the years ended December 31, 2003 and 2002, respectively.



46




ARENA RESOURCES, INC.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2003 AND 2002





Income Taxes – Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes on temporary differences between the amount of taxable income and pretax financial income and between the tax bases of assets and liabilities and their reported amounts in the financial statements.  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.


Basic and Diluted Income (Loss) Per Share – Basic income (loss) per common share is computed by dividing income (loss) attributable to common shareholders by the weighted-average number of common shares outstanding during the period.  Diluted income (loss) per share is calculated to give effect to potentially issuable common shares except during loss periods when those potentially issuable common shares would decrease loss per common share.  There were 507,200 warrants outstanding at December 31, 2002 that were excluded from the calculation of diluted loss per common share during the year ended December 31, 2002 because they were anti-dilutive.


Major Customers – 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.  During the year ended December 31, 2002, sales to two customers represented 47% and 31% of total sales. At December 31, 2002, these customers made up 56% and 19% of accounts receivable, respectively.


Stock-Based Employee Compensation – On April 1, 2003 and on August 12, 2003, 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.  Under APB 25, no stock-based compensation expense was charged to earnings, as all options granted had an exercise price equal to or greater than the adjusted fair value of the underlying common stock on the grant date.


Alternately, Statement on 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 income (loss) per common share if the Company had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation:


For the Years Ended December 31,

 

2003

 

2002

Net income, as reported

 

 

 $             824,322

 

 $             402,694

Deduct:  Total stock-based employee compensation expense determined under the

 

 

fair value based method for all awards, net of related tax effects

              (391,683)

 

                          -   

 

 

 

 

 

 

 

Pro Forma Net Income

 

 $             432,639

 

 $             402,694

 

 

 

 

 

 

 

Income (Loss) per Common Share

 

 

 

 

 

Basic, as reported

 

 

 $                   0.12

 

 $                  (0.09)

 

Basic, pro forma

 

 

 $                   0.06

 

 $                  (0.09)

 

 

 

 

 

 

 

 

Diluted, as reported

 

 $                   0.12

 

 $                  (0.09)

 

Diluted, pro forma

 

 

 $                   0.06

 

 $                  (0.09)

 

 

 

 

 

 

 



47




ARENA RESOURCES, INC.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2003 AND 2002






The pro forma estimated after-tax stock-based compensation expense under SFAS 123 for the years ending December 31, 2004, 2005 and 2006 relating to options outstanding at December 31, 2003, will be approximately $362,000, $214,000 and $126,000, respectively.


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 income per common share.


Recent Accounting Pronouncements – In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal activities.  The statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The Company has not been involved in any exit or disposal activities; therefore the adoption of the statement on January 1, 2003 did not have an impact on the Company’s financial position or results of operations.


In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. The interpretation requires that a liability measured at fair value be recognized for guarantees. The Company has not provided any guarantees and therefore the adoption of the interpretation had no impact on the Company’s financial statements.


In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure. Under the requirements of this statement, the Company has disclosed the effects on reported net of the Company’s accounting policy with respect to stock-based employee compensation.


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. The Company does not have an interest in a variable interest entity and the adoption of the statement did not have an impact on the Company’s 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 the Company 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. The Company issued a put option in exchange for oil and gas property interests in August 2002. The put option was originally classified as a liability; therefore, the adoption of the statement did not have an impact on the Company’s financial statements.



48




ARENA RESOURCES, INC.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2003 AND 2002





NOTE 2 – EARNING PER SHARE INFORMATION


For the Years Ended December 31,

 

2003

 

2002

Income before cumulative effect of change in accounting principle

 $             836,135

 

 $             402,694

Less: Preferred stock dividends

 

                          -   

 

               (798,018)

Income (loss) before cumulative effect of change in accounting principle

 

 

 

   attributable to common shares

 

                836,135

 

               (395,324)

Cumulative effect of change in accounting principle

                (11,813)

 

                          -   

Income (Loss) Attributable to Common Shares

 $             824,322

 

 $            (395,324)

Basic weighted-average common shares outstanding

             6,759,858

 

             4,553,232

Effect of dilutive securities

 

 

 

 

Warrants

 

 

                231,476

 

                          -   

Stock options

 

 

                250,342

 

                          -   

Diluted Weighted-Average Common Shares Outstanding

             7,241,676

 

             4,553,232

Basic Income (Loss) Per Common Share

 

 

 

 

Before cumulative effect of change in accounting principle

 $                   0.12

 

 $                  (0.09)

Cumulative effect of change in accounting principle

                          -   

 

                          -   

Net Income (Loss) Attributable to Common Shares

 $                   0.12

 

 $                  (0.09)

Diluted Income (Loss) Per Common Share

 

 

 

Before cumulative effect of change in accounting principle

 $                   0.12

 

 $                  (0.09)

Cumulative effect of change in accounting principle

                          -   

 

                          -   

Net Income (Loss) Attributable to Common Shares

 $                   0.12

 

 $                  (0.09)

 

 

 

 

 

 

 


NOTE 3 – ACQUISITION OF OIL AND GAS PROPERTIES


Koehn Property – On March 12, 2002, the Company entered into a farm-out agreement relating to certain oil and gas property in Haskell and Gray Counties, Kansas referred to as the Koehn Property. Under the terms of the agreement, the Company agreed to drill one well and could drill additional wells on the property. In exchange for each well drilled, the Company 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, completing and operating the well. After payout, the Company’s working interest in the wells and related oil and gas will decrease to 75% (60% of the net revenue interest). The Company successfully drilled one well at a cost of approximately $127,000. The well found proved gas reserves but is currently shut-in pending a pipeline connection.


On March 20, 2002, the Company entered into an agreement with Petro Consultants, Inc. (“Petro”), a related-party shareholder of the Company, which agreement created a joint venture between the two companies 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, the Company issued 70,000 shares of common stock to Petro to repurchase the 27% working interest in the well. The transactions with Petro have been recognized as a financing arrangement and have been accounted for as the issuance of 70,000 shares of common stock for $88,200 in cash, or $1.26 per share, without other rights to the property.


Dodson – On April 26, 2002, the Company purchased a working interest in a mineral lease located in Montague County, Texas in exchange for a cash payment of $200,000. In addition, the Company issued 25,000 shares of common stock to Petro as a finder’s fee, valued at $2.50 per share, or $62,500, based on the market value of the common stock on the date issued. The finder’s fee was capitalized as a cost of the mineral lease.



49




ARENA RESOURCES, INC.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2003 AND 2002





Ona Morrow – On June 18, 2002, the Company purchased a working interest in a mineral lease located in Texas County, Oklahoma for a cash payment of $735,000.


Eva South – On July 16, 2002, the Company purchased a working interest in a mineral lease located in Texas County, Oklahoma in exchange for a cash payment of $827,500. In addition, the Company issued 25,000 shares of common stock to Petro as a finder’s fee, valued at $4.00 per share, or $100,000, based on the market value of the common stock on the date issued. The finder’s fee was capitalized as a cost of the mineral lease.


Midwell, Appleby, Smalts and Hanes – On August 23, 2002, the Company entered into an agreement to purchase a working interest in mineral leases located in Cimarron County, Oklahoma. The cost of mineral interests acquired was $550,179 with the consideration given consisting of a cash payment of $100,000, the issuance of 99,885 shares of common stock valued at $399,540 or $4.00 per share based on the market value of the common stock on the date issued, the issuance of a put option to the seller valued at $87,269, less a call option received from the seller valued at $36,630.


Under the terms of the put option, the seller has the right on September 1, 2004, to require the Company to repurchase the 99,885 common shares at $4.00 per share. The issuance of the put option was recorded as a liability based on the holder’s ability to require the Company to pay cash to redeem the common stock and was recorded at its fair value of $87,269 on the date issued.  The fair value of the put option was computed using the Black-Scholes option pricing model with the following assumptions: 2.2% risk-free interest rate; 43% expected volatility; two years expected life and 0% dividend yield.


The call option received by the Company granted the Company the option to repurchase 50,000 of the common shares at $5.00 per share from the date issued through September 11, 2004. The call option is exercisable at the Company’s discretion and was therefore recorded as a reduction of additional paid-in capital based on its fair value of $36,630 on the date received. The fair value of the call option was determined using the Black-Scholes option pricing model with the following assumptions: 2.2% risk-free interest rate; 43% expected volatility; two year expected life and 0% dividend yield. The call option is part of permanent equity and will not be revalued at any future date.


Seven Rivers Queen Unit - On April 4, 2003, the Company entered into an agreement to purchase a 70.60% working interest, representing a 56.48% net revenue interest, in the Seven Rivers Queen Unit mineral lease located in Lea County, New Mexico.  Total consideration provided by the Company was a cash payment of $900,000.  The Company also issued 10,000 shares of common stock as a finder’s fee relating to this acquisition to an unrelated third party, which were valued at $5.20 per share, or $52,000. The value of the shares was based on the market value of the Company’s common stock on the date issued.


Beals Prospect - On July 2, 2003, the Company entered into an agreement to purchase a 100% working interest, representing a 80.5% net revenue interest, in the Beals Prospect mineral lease located in Comanche County, Kansas.  Total consideration provided by the Company was a cash payment of $60,000 and the issuance of 15,000 shares of common stock as a finder’s fee to an unrelated third party, which were valued at $5.80 per share, or $87,000.  The value of the shares was based on the market value of the Company’s common stock on the date issued. The prospect was unproven, undeveloped acreage. The Company entered into an agreement with Petro Consultants, Inc., a shareholder of the Company, whereby Petro paid the Company $180,000 for a 35% working



50




ARENA RESOURCES, INC.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2003 AND 2002





interest in an explorative well that the Company agreed to drill on the prospect. The cost of the well and the carrying value of the property were reduced by the proceeds received from Petro. When the well was drilled, it was unsuccessful and was plugged and abandoned.


North Benson Queen Unit Effective October 1, 2003, the Company acquired a 100% working interest, representing a 78.15% net revenue interest, in the North Benson Queen Unit in Eddy County New Mexico.  Total consideration provided by the Company was a cash payment of $500,000 and the issuance of 25,000 shares of common stock as a finder’s fee to an unrelated third party, which were valued at $5.64 per share, or $141,000. The value of the shares was based on the market value of the Company’s common stock on the date issued.


West San Andres Unit Effective October 1, 2003, the Company acquired a 100% working interest, representing a 79.60% net revenue interest, in the West San Andres Unit in Yoakum County, Texas.  Total consideration provided by the Company was a cash payment of $500,000 and the issuance of 7,000 shares of common stock as a finder’s fee to an unrelated third party, which were valued at $5.65 per share, or $39,550. The value of the shares was based on the market value of the Company’s common stock on the date issued.


NOTE 4 – NOTES PAYABLE AND PUT OPTION


On February 3, 2003, the Company established a $10,000,000 revolving credit facility with a bank with an initial borrowing base of $2,000,000.  The interest rate is a floating rate equal to the JP Morgan Chase prime rate plus 1% with interest payable monthly. Annual fees for the facility are 1/2 of one percent of the unused portion of the borrowing base. Amounts borrowed under the revolving credit facility will be due in February 2005. 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 and the credit facility was guaranteed by two of the Company’s officers. The Company is required under the terms of the credit facility to maintain a tangible net worth of $4,000,000, 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. The Company is presently current on its undertakings to the bank necessary to maintain this credit facility.  As of December 31, 2003, no amounts are owed under this credit facility.


On December 31, 2003, the Company entered into an agreement that increased it’s revolving credit facility to $20,000,000 and increased the initial borrowing base to $4,000,000.  Additionally, the agreement extended the maturity date to December 31, 2005, annual fees for the facility have been decreased to ¼ of 1% of the unused portion of the borrowing base, the Company is now required to maintain a tangible net worth of $6,000,000 and the personal guaranties of the two Company officers are released.  All other terms and conditions of the credit facility remain unchanged.


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 payable monthly with principal and interest due December 31, 2002. The notes are secured by all mineral interests, rights and equipment of the Company but have been subordinated to the bank revolving credit facility. On December 30, 2002, the Company and the officers agreed to an 18 month extension to the notes payable, extending the maturity date to June 30, 2004. On August 1, 2003, the Board of Directors and the officers agreed to an additional extension of the notes to January 1, 2005, 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 both December 31, 2003 and 2002.



51




ARENA RESOURCES, INC.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2003 AND 2002






The Company granted a put option in connection with the acquisition of oil and gas properties in August 2002. Under the terms of the put option, the seller has the right on September 1, 2004, to require the Company to repurchase the 99,885 common shares at $4.00 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 December 31, 2003 and 2002, the fair value of the liability was $2,905 and $50,604, respectively, calculated using the Black-Scholes option pricing model with the following assumptions: 1.1% and 1.8% risk-free interest rate; 32% and 36% volatility; 0.67 years and 1.7 years expected life; and 0% and 0% dividend yield.


NOTE 5 – ASSET RETIREMENT OBLIGATION

Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations, which requires entities to record the fair value of a liability for an asset retirement obligation when it is incurred which, for the Company, is typically when an oil or gas well is drilled or purchased. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal use of the asset.  The Company’s asset retirement obligations relate primarily to the obligation to plug and abandon oil and gas wells and support wells at the conclusion of their useful lives.

SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. When the liability is initially recorded, the related cost is capitalized by increasing the carrying amount of the related oil and gas property.  Over time, the liability is accreted upward for the change in its present value each period until the obligation is settled. The initial capitalized cost is amortized as a component of oil and gas properties as described in Note 1.

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 following present pro forma net income and basic and diluted income (loss) per common share as if SFAS No. 143 had been applied retroactively for the year ended December 31, 2003 and 2002:


For the Years Ended December 31,

 

2003

 

2002

Net Income

 

 

 $             836,135

 

 $             393,041

Income (Loss) Per Common Share

 

 

 

 

Basic

 

 

 $                   0.12

 

 $                   0.09

Diluted

 

 

 $                   0.12

 

 $                   0.09

 

 

 

 

 

 

 


The pro forma amount of the liability for the asset retirement obligation was $80,140 at December 31, 2001 and $236,718 at December 31, 2002. The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The reconciliation of the asset retirement obligation for the year ended December 31, 2003 is as follows:



52




ARENA RESOURCES, INC.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2003 AND 2002






Balance, January 1, 2003

 

 

 

 $             236,718

Liabilities incurred

 

 

 

 

                338,270

Accretion expense

 

 

 

 

                  32,212

Balance, December 31, 2003

 

 

 

 $             607,200

 

 

 

 

 

 

 


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 – In June 2001, Arena commenced a Private Placement Offering of 10% convertible preferred shares to accredited investors to raise between $525,000 and $3,500,000 for drilling and completions, as well as additional acquisitions.  The offering closed June 30, 2002 with gross proceeds of $3,301,128 and net proceeds of $2,961,495, after cash offering costs totaling $339,633.


During the year ended December 31, 2002, the Company collected $5,733 of subscriptions receivable that were outstanding at December 31, 2001.  From January 1, 2002 through July 1, 2002, the Company issued 1,028,786 shares of Class A convertible preferred stock at $1.75 per share under the terms of the private placement offering and realized gross proceeds during that period of $1,800,376 before cash offering costs of $216,503.  Offering costs included a 10% cash commission paid to the placement agents on shares they placed.  The Company issued the placement agents warrants to purchase 236,786 shares of common stock at $1.75 per share for a period of three years.  The Company valued the warrants issued to the placement agents at $254,889 and accounted for the warrants as an additional offering cost.  The fair value of the warrants was determined using the Black-Scholes option-pricing model with the following weighted-average assumptions: risk free interest rate of 3.4%, volatility of 47%, expected life of 3 years and expected dividend yield of 0%.  


The Company determined that the issuance of Class A preferred stock issued in 2002 resulted in the related shareholders receiving a beneficial conversion option at the dates the preferred stock was issued. This beneficial conversion option was valued at $114,402 based on the difference between the effective conversion price and the market value of the Company’s common stock on the dates issued.  Since the preferred shares were immediately convertible into common stock, the Company recognized the beneficial conversion option as preferred stock dividends on the dates the preferred stock was issued.


The Class A preferred stock was convertible into common shares from the date of issuance on a 1-for-1 ratio.  The Class A preferred shares were automatically convertible into common shares if the price of the common shares was equal to or greater than $4.00 for 20 consecutive days.  After one year, the Class A preferred shares were redeemable by the Company, subject to a 30-day notice, at $1.84 per share plus payment of any accrued dividends.  The Class A preferred shares accrued dividends at the rate of $0.175 per share annually and were payable quarterly.  The Class A preferred shares were non-voting and were entitled to priority over the common shares in the payment of dividends and in liquidation.


On July 30, 2002, the Company’s common stock was priced at or above $4.00 per share for the twentieth consecutive day.  Accordingly, the 1,886,359 shares of Class “A” preferred stock were converted into 1,886,359 shares of common stock on July 30, 2002.



53




ARENA RESOURCES, INC.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2003 AND 2002





The provisions of the preferred stock dictate that dividends will be paid up to the date of conversion or for one year from the date of issuance, whichever is later; accordingly, the Company accrued all remaining cash dividends that were payable in connection with the Series A preferred stock conversion on July 30, 2002. The total Series A preferred stock 2002 dividends payable in cash were $274,589. The Company paid $114,685 in preferred dividends during the year ended December 31, 2003 and $196,048 during the same period of 2002.  All accrued dividends have been paid.


On October 1, 2002, the Company offered all former Class A preferred shareholders additional restricted common shares equal to 10% of the common shares issued upon conversion of the preferred stock in exchange for their agreement and consent not to engage in any sales, assignments or rights related to the common stock issued for a period of twelve months from the earliest date the common stock could otherwise be traded under existing restricted stock agreements or federal securities regulations.  Under that offer, the Company issued 181,387 common shares to the former Class A preferred shareholders.  In addition, the Company issued the placement agents 18,139 common shares as compensation for obtaining the related lock up agreements.  The Company recognized the common shares issued as preferred stock dividends and valued them at $409,027 or $2.05 per share based on the market value of the common stock on the dates the offer was accepted.


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.  Through December 31, 2002, the Company had issued 286,000 shares of common stock and warrants under the terms of the private placement offering for gross proceeds of $715,000 before cash offering costs of $112,864 and were allocated to the common stock issued and the warrants based upon their relative fair value. Accordingly, $493,821 was allocated to the 286,000 shares of common stock, and $108,315 was allocated to the 286,000 warrants. Although the amount allocated to the warrants was less than their fair value, the fair value of the warrants was $278,015 determined using the Black-Scholes option pricing model with the following assumptions: risk free interest rate of 1.8%, expected dividend yield of 0%, volatility of 36.5%, and expected lives of 2.8 years.


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.


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.



54




ARENA RESOURCES, INC.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2003 AND 2002





During the years ended December 31, 2003 and 2002, warrant holders exercised 19,400 warrants for $33,950 or $1.75 per share and exercised 74,786 warrants for $130,876 or $1.75 per share, respectively. Additionally, 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.


Stock purchase warrants issued and exercised during the years ended December 31, 2003 and 2002 are summarized as follows:


 

 

 

2003

 

2002

 

 

 

 Warrants

 Weighted-Average

 

 Warrants

 Weighted-Average

 

 

 

 

 Exercise Price

 

 

 Exercise Price

Outstanding at beginning of year

       507,200

$3.58   

 

       59,200

$1.75  

Issued

 

       947,923

4.89

 

     522,786

3.53

Exercised

 

       (19,400)

1.75

 

      (74,786)

1.75

        

Outstanding at End of Year

    1,435,723

$4.47  

 

     507,200

$3.58  

        


Stock purchase warrants outstanding at December 31, 2003 are as follows:


   

 Weighted-Average

 

 Warrants

Exercise

 Remaining

 

 Outstanding

Price

 Contractual Life

 

         201,800

$1.75

         1.5 years

 

           50,000

3.00

2.5

 

      1,183,923

5.00

1.7

    
 

      1,435,723

  
    


Call Option – The Company received a call option in August 2002 in connection with the purchase of oil and gas properties. The option permits the Company to repurchase 50,000 shares of its common stock at $5.00 per share through September 11, 2004. 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 $36,630 on the date received. The fair value of the call option was determined using the Black-Scholes option pricing model with the following assumptions: 2.2% risk-free interest rate; 43% expected volatility; two year expected life and 0% dividend yield. The call option is part of permanent equity and will not be revalued.





ARENA RESOURCES, INC.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2003 AND 2002





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 options vest at the rate of 20% each year over five years beginning one year from the date granted. The exercise price was 85% of the market value of the Company’s common stock on the dates issued.  In accordance with FASB Interpretation No. 44, Accounting for Certain Transactions Involving Stock Compensation, the 15% discount from the market price of the Company’s common stock used in determining the fair value of the common stock is considered reasonable and the options are not compensatory. Accordingly, the Company did not recognize any compensation expense from the grant of these stock options. A summary of the status of the stock options as of December 31, 2003 and changes during the year then ended is as follows:



55




ARENA RESOURCES, INC.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2003 AND 2002






 

 

 

 

 Weighted-Average

 

 

 

 Options

 Exercise Price

Granted

 

    1,050,000

$3.75   

Forfeited

 

       (50,000)

3.70

     

Outstanding at End of Year

    1,000,000

$3.76  

     

Options exercisable at end of year

                 -   

 

     


The fair value of the options granted, net of forfeitures, was $1,862,864, or $1.86 per share, and was estimated on the dates granted using the Black-Scholes option-pricing model with the following weighted-average assumptions: dividend yield of 0% percent, 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 stock options at December 31, 2003 was 4.2 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 4.


In 2002, the Company issued common stock to Petro Consultants, Inc. for cash and as compensation for finding and arranging for the purchase of oil and gas properties, as described in Note 3. Petro Consultants, Inc. was a related party shareholder of the Company due to an officer of Petro Consultants, Inc. serving as a director and a consultant to the Company from July 1, 2002 to July 2003. Due to the resignation from that position and relationship, Petro Consultants, Inc. is no longer considered a related party.  In August 2003, the Company sold an interest in an explorative well to Petro Consultants, Inc for $180,000 as described in Note 3.


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.  Under terms of the lease, the Company pays $1,700 per month through December 31, 2005. The Company incurred lease expense of $10,640 for the year ended December 31, 2003. The future minimum lease payments under the operating lease agreement as of December 31, 2003 consist of $20,400 due during the year ending December 31, 2004 and $20,400 due during the year ending December 31, 2005.


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 $256,529 to allow the Company to do business in those states.  The standby letters of credit are collateralized by an assignment of certificates of deposit totaling $25,000 and by the credit facility with a bank. 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.



56




ARENA RESOURCES, INC.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2003 AND 2002





NOTE 10 – INCOME TAXES


The provision for income taxes consisted of the following:


For the Years Ended December 31,

 

2003

 

2002

Current before benefit of operating loss carry forwards

 $               83,686

 

 $                       -   

Current benefit of operating loss carry forwards

                (83,686)

 

                          -   

Deferred

 

 

                491,599

 

                187,193

 

 

 

 

 

 

 

Provision for Income Taxes

 

 $             491,599

 

 $             187,193

 

 

 

 

 

 

 


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,

 

2003

 

2002

Tax at federal statutory rate (34%)

 

 $             451,430

 

 $             200,562

Income not subject to tax

 

                (17,364)

 

                 (22,168)

State tax, net of federal benefit

 

                  57,533

 

                  19,466

Benefit of operating loss carry forwards

 

                          -   

 

                 (10,667)

 

 

 

 

 

 

 

Provision for Income Taxes

 

 $             491,599

 

 $             187,193

 

 

 

 

 

 

 


As of December 31, 2003, the Company had net operating loss carry forwards for federal income tax reporting purposes of $39,471 which, if unused, will expire in 2022. The net deferred tax liability consisted of the following:


December 31,

 

 

2003

 

2002

Deferred tax liabilities

 

 

 

 

 

 

Depreciation and amortization

 

 $               56,158

 

 $                       -   

 

Intangible drilling costs

 

                648,126

 

                264,851

 

Asset retirement costs

 

                208,690

 

                          -   

 

Total deferred tax liabilities

 

                912,974

 

                264,851

Deferred tax assets

 

 

 

 

 

 

Asset retirement liability

 

                226,486

 

                          -   

 

Operating loss carry forwards

 

                  14,723

 

                  77,658

 

Total deferred tax assets

 

                241,209

 

                  77,658

 

 

 

 

 

 

 

Net Deferred Income Taxes

 

 $             671,765

 

 $             187,193

 

 

 

 

 

 

 


NOTE 11 – SUBSEQUENT EVENTS


Subsequent to December 31, 2003, the Company has drilled and completed the Rexford #1-30 well in Haskell County, Kansas, on the acreage covered by the farm-out agreement entered into on March 12, 2002 as part of the Koehn lease.  The well was successful, but has not yet been connected.  It is anticipated to be connected later this year.


Subsequent to December 31, 2003, warrants to acquire 5,000 shares of common stock have been exercised (unaudited).



57




ARENA RESOURCES, INC.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

(Unaudited)





Capitalized Costs Relating to Oil and Gas Producing Activities

 

 

 

 

 

 

 

 

 

 

December 31,

 

 

2003

 

2002

Unproved oil and gas properties

 

 $        128,694

 

 $                  -   

Proved oil and gas properties

 

        8,334,706

 

        4,884,804

Drilling advances on uncompleted projects

 

           351,000

 

                     -   

Support and office equipment

 

             67,458

 

             36,466

Total capitalized costs

  

        8,881,858

 

        4,921,270

Less accumulated depreciation and amortization

         (513,754)

 

         (172,258)

       

Net Capitalized Costs

 

 

 $     8,368,104

 

 $     4,749,012

       
       

Costs Incurred in Oil and Gas Producing Activities

   
       

For the Years Ended December 31,

 

2003

 

2002

Acquisition of proved properties

 

 $     2,470,821

 

 $     2,659,832

Acquisition of unproved properties

 

           147,000

 

                     -   

Exploration costs

  

           326,410

 

                     -   

Development costs

  

           849,864

 

           579,153

Acquisition of support and office equipment

  

             29,388

Asset retirement costs recognized upon adoption of SFAS No. 143

           221,218

 

                     -   

       

Total Costs Incurred

 

 

 $     4,015,313

 

 $     3,268,373

       


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,

 

2003

 

2002

Oil and gas revenues

  

 $     3,665,477

 

 $     1,657,037

Production costs

  

      (1,149,136)

 

         (594,863)

Production taxes

  

         (269,563)

 

         (117,164)

Depreciation and amortization

 

         (338,157)

 

         (127,847)

General and administrative expense

 

         (557,576)

 

         (248,018)

Results before income taxes

 

        1,351,045

 

           569,145

Provision for income taxes

 

         (491,599)

 

         (187,193)

       

Results of Oil and Gas Producing Operations

 $        859,446

 

 $        381,952

       


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


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



58




ARENA RESOURCES, INC.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

(Unaudited)





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,

 2003

 

 2002

 

 

 

Oil 1

 

Gas 1

 

Oil 1

 

Gas 1

 Proved Developed and Undeveloped Reserves

       

 Beginning of year

 

    5,982,686

 

    3,187,757

 

       494,823

 

    2,960,373

 Purchases of minerals in place

    3,175,357

 

       570,924

 

    5,465,906

 

    1,676,706

 Improved recovery

 

         18,066

 

       229,626

 

                -   

 

                -   

 Production

 

     (117,646)

 

       (67,329)

 

       (58,717)

 

       (46,819)

 Revision of previous estimates

     (139,546)

 

     (512,224)

 

         80,674

 

  (1,402,503)

          

 End of Year

 

    8,918,917

 

    3,408,754

 

    5,982,686

 

    3,187,757

          

 Proved Developed Reserves at End of Year

    1,580,531

 

    1,612,738

 

       750,464

 

    1,151,985

          


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


Standardized Measure of Discounted Future Net Cash Flows

   
       

December 31,

 

 

2003

 

2002

Future cash inflows

  

 $ 272,687,194

 

 $ 154,639,383

Future production and development costs

 

    (87,622,591)

 

    (42,401,610)

Future income taxes

 

 

    (60,917,690)

 

    (36,580,859)

Future net cash flows

  

    124,146,913

 

      75,656,914

10% annual discount for estimated timing of cash flows

    (62,335,966)

 

    (33,180,087)

       

Standardized Measure of Discounted Future Net Cash Flows

 $   61,810,947

 

 $   42,476,827

       


Changes in Standardized Measure of Discounted Future Net Cash Flows

   
       

For the Years Ended December 31,

 

2003

 

2002

Beginning of the year

  

 $   42,476,827

 

 $     5,203,372

Purchase of minerals in place

 

      21,333,720

 

      48,956,314

Extensions, discoveries and improved recovery, less related costs

           691,469

 

                     -   

Development costs incurred during the year

 

           320,102

 

           215,433

Sales of oil and gas produced, net of production costs

      (2,302,405)

 

      (1,057,366)

Accretion of discount

  

        4,496,888

 

        3,525,683

Net changes in prices and production costs

 

      11,873,094

 

        6,456,827

Net change in estimated future development costs

             42,383

 

         (142,491)

Revision of previous quantity estimates

 

           (24,513)

 

      (2,497,666)

Revision in estimated timing of cash flows

 

      (7,110,749)

 

                     -   

Net change in income taxes

 

      (9,985,869)

 

    (18,183,279)

       

End of the Year

 

 

 $   61,810,947

 

 $   42,476,827

       



59







Exhibit Index


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 December 31, 2003, among Arena Resources, Inc. and Bank of Oklahoma, N.A.


10.2

Form of. Stock Option Subscription Agreements (ii)


23

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


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 Resource, Inc.’s Form SB-1 filed September 20, 2000, (SEC File No. 333-46164)].


(ii)  Incorporated by reference to Arena Resource, Inc.’s Form 10-QSB, filed May 15, 2003.