| (Mark One) |
| |X| Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
| For the fiscal year ended December 31, 2004 |
| Or |
| |__| Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
| For the transition period from ___________to ___________ |
_________________
_________________
| 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
_________________
| 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 |X| 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. |X|
State issuer's revenues for its most recent fiscal year. $8,482,130
As of March 10, 2005, the aggregate market value of the common voting stock held by non-affiliates of the issuer, based upon the closing stock price of $12.61 per share, was approximately $97,905,351. As of March 10, 2005, the issuer had outstanding 10,194,304 shares of common stock ($0.001 par value).
Transitional Small Business Disclosure Format (check one): Yes |_| No |X|
| TABLE OF CONTENTS | |||||
|---|---|---|---|---|---|
| PART I | |||||
| Page | |||||
| Item 1 | Description of Business | 4 | |||
| Item 2 | Description of Property | 7 | |||
| Item 3 | Legal Proceedings | 20 | |||
| Item 4 | Submission of Matters to a Vote of Security Holders | 20 | |||
| PART II | |||||
| Item 5 | Market for Registrant's Common Equity; Related Stockholder Matters and Small Business Issuer Purchases of Equity Securities | 21 | |||
| Item 6 | Management's Discussion and Analysis of Financial Condition and Results of Operations | 23 | |||
| Item 7 | Financial Statements | 32 | |||
| Item 8 | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | 32 | |||
| Item 8A | Controls and Procedures | 32 | |||
| Item 8B | Other Information | 32 | |||
| PART III | |||||
| Item 9 | Directors and Executive Officers | 32 | |||
| Item 10 | Executive Compensation | 36 | |||
| Item 11 | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 38 | |||
| Item 12 | Certain Relationships and Related Transactions | 39 | |||
| Item 13 | Exhibits | 39 | |||
| Item 14 | Principal Accountant Fees and Services | 40 | |||
The purpose of this Amendment No. 2 to the Annual Report on Form 10-KSB of Arena Resources, Inc. (the “Company”) for the year ended December 31, 2004 (the “Original Form 10-KSB”) is to (i) include the GAAP-based “Standardized Measure of Discounted Future Net Cash Flows” in various narrative and tabular provisions where we describe the non-GAAP concept of pre-tax present value of future net reserves (“PV-10”) and explain the reason for the difference in the two measures; (ii) reclassify certain costs which we had previously included as part of our oil and gas production activities; (iii) disclose more fully the impact of SFAS No. 143 on our calculation of depreciation, depletion and amortizations costs; (iv) record an adjusted value (adjusted to market value on the date of issuance) of 40,000 shares of the Company’s common stock originally issued as a “finders’ fee” in connection with the acquisition of property and capitalized as part of our properties subject to amortization; and (v) to restate our financial statements to reflect the change in how we account for compensation expenses associated with options granted to employees under our stock option plan.
The change in how we account for compensation expenses associated with options granted to employees essentially results in our recognition of compensation expense related to the discount amount of the exercise price of the option from the market price of the stock at the date of grant over the vesting period. The discount on all options granted through December 31, 2004 has been 15%, and the vesting period has been five years. The result of these changes is that our general and administrative expenses (which include our current compensation expense) have increased, with a resulting reduction in our net income after taxes for each year we have restated our financial statements. The effect of this change on our net income after taxes is to reduce our net income for the year ended December 31, 2003 by $139,355 (from $809,498 to $670,143), which equates to a reduction in our earnings per share from $0.12 to $0.10 for basic earnings per share and from $0.11 to $0.09 for diluted earnings per share, and for the year ended December 31, 2004 by $128,365 (from $2,580,017 to $2,451,652), which equates to a reduction in our earnings per share from $0.33 to $0.31 for basic earnings per share and from $0.30 to $0.28 for diluted earnings per share. We direct your attention to new Note 2 to our financial statements, which explains more fully these changes.
This Amendment No. 2 amends and restates in its entirety the Original Form 10-KSB. This Amendment No. 2 continues to reflect circumstances as of the date and time of the filing of the Original Form 10-KSB and does not reflect events occurring after the filing of the Original Form 10-KSB or modify or update any other disclosures in any way.
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.
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 focus will be on developing our existing properties, while continuing to pursue acquisitions of oil and gas properties with upside potential.
Since our inception in August 2000, we have built our asset base and achieved growth primarily through property acquisitions. From our inception through December 31, 2004, we have increased our proved reserves to approximately 21.2 million Boe (barrel of oil equivalent), through the acquisition of interests in 12 leases, which have net revenue interests ranging from 24.5% to 81.32%. As of December 31, 2004, our estimated proved reserves had a pre-tax PV10 (present value of future net revenues before income taxes discounted at 10%) of approximately $302 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $205 million. The difference between these two amounts is the effect of income taxes. The Company presents the pre-tax PV-10 value, which is a non-GAAP financial measure, because it is a widely used industry standard which we believe is useful to those who may review this Annual Report when comparing our asset base and performance to other comparable oil and gas exploration and production companies. We spent approximately $30 million on acquisitions and capital projects during 2003 and 2004.
We have a portfolio of oil and natural gas reserves, with approximately 92% of our proved reserves consisting of oil and approximately 8% consisting of natural gas. Approximately 24.1% of our proved reserves are classified as proved developed producing, or “PDP.” Approximately 1.7% of our proved reserves are classified as proved developed non-producing, or “PDNP,” and approximately 74.2% are classified as proved undeveloped, or “PUD.”
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).
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 2004, two customers were responsible for generating 74% or more of our total oil and natural gas sales. These two customers were Plains Marketing, L.P., accounting for approximately 31% of total sales and Navajo Refining Company, accounting for approximately 43% of total sales. However, we believe that the loss of either of these customers would not materially impact our business, because we could readily find other purchasers for our oil and gas as produced.
Regulation of Transportation of Oil
Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission, or the FERC, regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state.
Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors. Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
Regulation of Transportation and Sale of Natural Gas
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.
Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.
Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors.
Regulation of Production
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Our oil and natural gas exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Historically, most of the environmental regulation of oil and gas production has been left to state regulatory boards or agencies in those jurisdictions where there is significant gas and oil production, with limited direct regulation by such federal agencies as the Environmental Protection Agency. However, while we believe this generally to be the case for our production activities in Oklahoma, Texas, New Mexico and Kansas, there are various regulations issued by the Environmental Protection Agency (“EPA”) and other governmental agencies that would govern significant spills, blow-outs, or uncontrolled emissions.
In Oklahoma, Texas, New Mexico and Kansas specific oil and gas regulations apply to the drilling, completion and operations of wells, and the disposal of waste oil and salt water. There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.
At the federal level, among the more significant laws and regulations that may affect our business and the oil and gas industry are: The Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as “CERCLA” or “Superfund; the Oil Pollution Act of 1990; the Resource Conservation and Recovery Act, also known as “RCRA,”; the Clean Air Act; Federal Water Pollution Control Act of 1972, or the Clean Water Act; and the Safe Drinking Water Act of 1974.
Compliance with these regulations may constitute a significant cost and effort for us. No specific accounting for environmental compliance has been maintained or projected by us at this time. We are not presently aware of any environmental demands, claims, or adverse actions, litigation or administrative proceedings in which either us or our acquired properties are involved or subject to, or arising out of any predecessor operations.
In the event of a breach of environmental regulations, these environmental regulatory agencies have a broad range of alternative or cumulative remedies which include: ordering a clean-up of any spills or waste material and restoration of the soil or water to conditions existing prior to the environmental violation; fines; or enjoining further drilling, completion or production activities. In certain egregious situations the agencies may also pursue criminal remedies against us or our principal officers.
As of December 31, 2004, we had ten 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.
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, 2004, our proved reserves have grown to 21,217,254 Boe, at an average acquisition/drilling cost of $1.60 per Boe. Many properties contain both oil and gas reserves. In those cases, the oil and gas reserves and the volume of oil and gas produced are converted to a common unit of measure on the basis of their approximate relative energy content. The common unit which we use is “Barrels of oil equivalent” or “Boe.” Acquisition and drilling costs “per Boe” is calculated by dividing the net capitalized costs, computed in accordance with applicable accounting standard, as shown under “Capitalized Costs Relating to Oil and Gas Producing Activities” under Supplemental Information on Oil and Gas Producing Activities ($33,879,101), by our reserves in Boe (21,217,254).
As of December 31, 2004, our estimated proved reserves had a pre-tax PV10 value of approximately $302 million and a Standardized Measure of Discounted Future Cash Flows of approximately $205 million, approximately 44% of which came from properties located in New Mexico, approximately 42% from our properties in Texas, approximately 12% from our properties in Oklahoma and approximately 2% from our properties in Kansas. We spent approximately $30 million on capital projects during 2003 and 2004. We expect to further develop these properties through additional drilling. Our capital budget for 2005 is approximately $15 million for development of existing properties. Although our focus will be on development of our existing properties, we also intend to continue seeking acquisition opportunities which compliment our current portfolio. We intend to fund our development activity primarily through use of cash flow from operations and cash on hand, while potential drawings on our credit facility and proceeds from future equity transactions would also be available for development projects or future acquisitions. We believe that our acquisition expertise, together with our operating experience and efficient cost structure, provides us with the potential to continue our growth.
We have a portfolio of oil and natural gas reserves, with approximately 92% of our proved reserves consisting of oil and approximately 8% consisting of natural gas. Approximately 24.1% of our proved reserves are classified as proved developed producing properties. Approximately 1.7% of our proved reserves are classified as proved developed nonproducing, and approximately 74.2% are classified as proved undeveloped.
The following table summarizes our total net proved reserves, pre-tax PV10 value and Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2004.
| Geographic Area | Oil (Bbl) |
Natural Gas (Mcf) |
Total (Boe) |
Pre-Tax PV10 Value | Standardized Measure of Discounted Future Net Cash Flows | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| New Mexico | 8,659,448 | 4,165,346 | 9,353,672 | $ | 132,918,983 | $ | 89,979,415 | ||||||||||
| Texas | 7,777,328 | 2,204,548 | 8,144,753 | 127,273,059 | 86,812,109 | ||||||||||||
| Oklahoma | 3,113,888 | 168,756 | 3,142,014 | 36,583,892 | 24,669,137 | ||||||||||||
| Kansas | -- | 3,460,891 | 576,815 | 5,680,048 | 3,780,089 | ||||||||||||
| Total | 19,550,664 | 9,999,541 | 21,217,254 | $ | 302,455,982 | $ | 205,240,750 | ||||||||||
Our 21,217,254 Boe of proved reserves, which consist of approximately 92% oil and 8% natural gas, are summarized below as of December 31, 2004, 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, 2004, New Mexico proved reserves had a net pre-tax PV10 value of $132.9 million and Standardized Measure of Discounted Future Net Cash Flows of $90.0 million, our proved reserves in Texas had a net pre-tax PV10 value of $127.2 million and Standardized Measure of Discounted Future Net Cash Flows of $86.8 million, our proved reserves in Oklahoma had a net pre-tax PV10 value of $36.6 million and a Standardized Measure of Discounted Future Net Cash Flows of $24.7 million and our proved reserves in Kansas had a net pre-tax PV10 value of $5.7 million and a Standardized Measure of Discounted Future Net Cash Flows of $3.8 million.
As of December 31, 2004, approximately 24.1% of the 21.2 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 1.7% and 74.2%, respectively, of the proved reserves as of December 31, 2004.
Approximately twenty-eight percent (28%) of our reserves for the year ended December 31, 2004 are associated with secondary recovery projects that are either in the initial stage of implementation or are scheduled for implementation. We anticipate that secondary recovery will be attempted by the use of waterflood of these reserves, and the exact project initiation dates and, by the very nature of waterflood operations, the exact completion dates of such projects, are uncertain. In addition, the reserves associated with these secondary recovery projects, as with any reserves, are estimates only, as the success of any development project, including these waterflood projects, cannot be ascertained in advance. If we are not successful in developing a significant portion of our reserves associated with secondary recovery methods, it could have a negative impact on our earnings and our stock price.
Total proved reserves had a net pre-tax PV10 value as of December 31, 2004 of approximately $302 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $205 million, 18.6% or $56.1 million and $38.2, respectively, of which is associated with the PDP reserves. An additional $4.7 million and $3.1 million, respectively, is associated with the PDNP reserves ($60.8 million and $41.3 million, respectively, for total proved developed reserves, or 20.1% of total proved reserves’ pre-tax PV10 value) and $241.6 million and $164.0 million, respectively, is associated with PUD reserves.
Our proved reserves as of December 31, 2004 are summarized in the table below.
| Oil (Bbl) |
Gas (Mcf) |
Total (Boe) |
% of Total Proved |
Pre-tax PV10 (In thousands) |
Standardized Measure of Discounted Future Net Cash Flows | Future Capital Expenditures (In thousands) | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| New Mexico: | ||||||||||||||||
| PDP | 2,273,402 | 2,070,556 | 2,618,495 | 12% | $ | 31,268 | $ | 21,218 | $ | - | ||||||
| PDNP | 326,902 | 250,734 | 368,691 | 2% | 4,696 | 3,187 | - | |||||||||
| PUD | 6,059,144 | 1,844,056 | 6,366,487 | 30% | 96,955 | 65,792 | 11,541 | |||||||||
| Total Proved: | 8,659,448 | 4,165,346 | 9,353,672 | 44% | $ | 132,919 | $ | 90,197 | $ | 11,541 | ||||||
| Texas: | ||||||||||||||||
| PDP | 1,661,082 | 584,328 | 1,758,470 | 8% | $ | 17,293 | $ | 11,735 | $ | - | ||||||
| PDNP | - | - | - | 0% | - | - | - | |||||||||
| PUD | 6,116,246 | 1,620,220 | 6,386,283 | 30% | 109,980 | 74,630 | 44,684 | |||||||||
| Total Proved: | 7,777,328 | 2,204,548 | 8,144,753 | 38% | $ | 127,273 | $ | 86,365 | $ | 44,684 | ||||||
| Oklahoma: | ||||||||||||||||
| PDP | 459,907 | 168,756 | 488,033 | 3% | $ | 4,731 | $ | 3,210 | $ | - | ||||||
| PDNP | - | - | - | 0% | - | - | - | |||||||||
| PUD | 2,653,981 | - | 2,653,981 | 12% | 31,853 | 21,615 | 5,375 | |||||||||
| Total Proved: | 3,113,888 | 168,756 | 3,142,014 | 15% | $ | 36,584 | $ | 24,825 | $ | 5,375 | ||||||
| Kansas: | ||||||||||||||||
| PDP | - | 1,540,891 | 256,815 | 1% | $ | 2,818 | $ | 1,912 | $ | - | ||||||
| PDNP | - | - | - | 0% | - | - | - | |||||||||
| PUD | - | 1,920,000 | 320,000 | 2% | 2,862 | 1,942 | 375 | |||||||||
| Total Proved: | - | 3,460,891 | 576,815 | 3% | $ | 5,680 | $ | 3,854 | $ | 375 | ||||||
| Total: | ||||||||||||||||
| PDP | 4,394,391 | 4,364,531 | 5,121,813 | 24% | $ | 56,110 | $ | 38,075 | $ | - | ||||||
| PDNP | 326,902 | 250,734 | 368,691 | 2% | 4,696 | 3,187 | - | |||||||||
| PUD | 14,829,371 | 5,384,276 | 15,726,750 | 74% | 241,650 | 163,979 | 61,975 | |||||||||
| Total Proved: | 19,550,664 | 9,999,541 | 21,217,254 | 100% | $ | 302,456 | $ | 205,241 | $ | 61,975 | ||||||
The following table indicates projected reserves that we currently estimate will be converted from proved undeveloped to proved developed, as well as the estimated costs per year involved in such development.
| Year | Estimated Oil Reserves Developed (Bbls) |
Estimated Gas Reserves Developed (Mcf) |
Total Boe | Estimated Development Costs(1) | ||||
|---|---|---|---|---|---|---|---|---|
| 2005 | 3,108,084 | 2,159,540 | 3,468,007 | $ | 12,406,208 | |||
| 2006 | 6,041,222 | 1,832,581 | 6,346,652 | 22,620,434 | ||||
| 2007 | 4,517,791 | 1,056,016 | 4,693,794 | 16,532,000 | ||||
| 13,667,097 | 5,048,137 | 14,508,453 | $ | 51,558,642 | ||||
(1) The amount shown for 2005 differs from the Capital Expenditures budgeted as described elsewhere in this document. The difference is the result of Arena owning less than 100% of the working interest in all of the properties which are being developed. The amount shown here and in our reserve analysis constitutes the portion attributable to our working interest. However, if our working interest partners elected not to participate in the development planned, we would be responsible for the full $15 million.
Our estimated average daily production for the month of December, 2004, is summarized below. These tables indicate the percentage of our estimated December 2004 average daily production of 999 Boe/d attributable to each state and to oil versus natural gas production.
| State | Average Daily Production |
Oil | Natural Gas | |||||
|---|---|---|---|---|---|---|---|---|
| New Mexico | 48.99% | 43.15% | 5.84% | |||||
| Texas | 24.40% | 22.99% | 1.41% | |||||
| Oklahoma | 22.21% | 20.15% | 2.06% | |||||
| Kansas | 4.40% | 0.00% | 4.40% | |||||
| Total | 100% | 86% | 14% |
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. This lease was acquired from Permian Resources Holding, Inc., an unaffiliated company, for a cash payment of $900,000. The remaining working interest is owned by unaffiliated parties. There are currently 43 producing wells on this lease, and we believe it can support six to eight possible infill wells (additional wells within the spacing requirements of the unit), as well as some untested formations in shallow sand. This lease consists of approximately 2,240 acres and is held by production.
North Benson Queen Unit – Eddy County, New Mexico. In October 2003 we acquired a 100% working interest and a 78.15% net revenue interest in this lease, which currently has 21 producing wells. This lease was acquired from United Resources, L.P., an unaffiliated company, for a cash payment of $500,000. The lease covers approximately 1,800 acres, and we currently anticipate it can support up to 23 additional wells, which are included in our estimate of PUD. This lease is held by production.
The North Benson Queen Unit Waterflood will require additional volumes of water to support the waterflood expansion. A sufficient and economical source of water has been identified. A water line of approximately four miles in length will be constructed across Bureau of Land Management lands to transport the water to the North Benson Queen Unit. Permit applications must be submitted to the Bureau of Land Management and are usually granted within ninety days of application submittal. The construction of the water line should require approximately thirty days at a cost of $250,000. The permit application will be submitted in the second quarter 2005 with construction slated for the summer of 2005. The development of the North Benson Queen Unit waterflood is scheduled for 2006 at estimated costs of $5,732,000.
East Hobbs Unit – Lea County, New Mexico. In May 2004 we acquired a 82.24% working interest and a 67.6% net revenue interest in this lease primarily from EnerQuest Oil and Gas, Ltd., an unaffiliated company, for a cash payment of $10,008,440. Although the Purchase and Sales Agreement transferred the revenue and the related operating costs from East Hobbs to us beginning March 1, 2004, Arena did not control the property interests until May 7, 2004. As a result, the acquisition date for accounting purposes was May 7, 2004 and the operations of East Hobbs’ operations were included in our results of operations from May 7, 2004. Revenues and operating costs for the months of March and April were estimated and treated as adjustments to the purchase price. This lease covers approximately 920 acres. At the date of acquisition, there were 20 operating oil and gas wells. We drilled an additional six wells, all of which were successfully completed, and washed down one other well during 2004. We believe this property can support up to six additional wells, which are included in our estimate of PUD. This lease is held by production.
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. This lease was acquired from Durango Operating Company, Inc. an unaffiliated company, for a cash payment of $750,000. There are currently 12 producing wells on this lease. A portion of this property has been waterflooded, and when we begin our future development operations on this property, we plan to waterflood the remaining acreage. A waterflood operation is a method of secondary recovery in which water is injected into the reservoir formation to displace residual oil. The water from injection wells physically sweeps the displaced oil to adjacent production wells. This potential waterflood project (and the estimated $1 million cost thereof) is included as PUD in our reserve report. This lease consists of approximately 1,697 acres and is held by production.
Dodson Lease – Montague County, Texas. We purchased a 100% working interest and an 81.25% net revenue interest in this lease in June 2002. This lease was acquired from Nocona minerals Partnership, an unaffiliated company, for a cash payment of $200,000. There are currently three producing wells and nine other wells on this approximately 570 acre lease, all of which is held by production.
West San Andres Unit – Yoakum County, Texas. In October 2003 we acquired a 100% working interest and a 79.60% net revenue interest in this lease from Permian Resources, Inc. an unaffiliated company, for a cash payment of $500,000. The lease covers approximately 1,200 acres, and currently has 10 producing wells. We believe it can support up to four additional wells, which are included in our estimate of PUD. This lease is held by production. In 2004 we contracted for the drilling of one well on this property, which was not commenced until January 2005.
Fuhrman-Mascho leases – Andrews County, Texas. In December 2004 we acquired a 100% working interest and a 75% net revenue interest in these leases from four entities; Paul D. Friemel & Assoc, Inc., Compostella Oil Company, Redco Oil & Gas Inc. and Terry N. Stevens, Inc., all unaffiliated companies. The purchase price, including acquisition costs, was $10,966,495 and consisted of $9,667,381 of cash paid to the sellers, $44,421 in cash acquisition costs, 180,013 shares of the Company’s common stock, valued at $1,260,091, or $7.00 per share, and the issuance of put and call options with a net value of $24,602. These leases cover approximately 11,300 acres. We believe it can support up to 130 additional wells, which are included in our estimate of PUD. These leases are held by production.
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. “Net revenue interest” is the owner’s percentage share of the monthly income realized from the sale of a well’s produced oil and gas. The net revenue interest is a lesser number as compared to the working interest, due to the mineral owner royalty and other overriding royalties on the well.
In May 2001, we acquired an additional 30% working interest in the lease from a group of interest holders represented by Petro Consultants, Inc. The additional working interest was valued at $300,000 and was acquired by the issuance of 80,000 shares of common stock valued at $1.75 per share totaling $140,000, the assumption of a $50,000 obligation of the seller and the issuance of a note payable for $110,000. This note was subsequently settled through cash payments of $45,000 and the issuance of an additional 37,143 shares of common stock valued at $1.75 per share totaling $65,000. The $50,000 liability assumed from the seller related to the seller’s previous obligation to the operator of the properties and has been paid.
In October 2001, we acquired an additional 24% working interest and a 2½% overriding royalty interest in the Casey lease from a group of interest holders represented by Petro Consultants, Inc. The acquired interests were valued at $266,250 and were purchased by the issuance of 81,857 shares of common stock valued at $1.75 per share totaling $143,250, a cash payment of $90,000 and the issuance of a note payable for $33,000. The note was subsequently paid.
The remaining working interest in the Casey lease is owned by an unaffiliated party. This lease consists of approximately 160 acres. In December 2003 we temporarily shut-in this gas well. Subsequent to December 31, 2004, we sold the Casey lease to an unrelated party.
Ona Morrow Sand Unit – Cimarron and Texas Counties, Oklahoma. We own a 100% working interest and an 81.32% net revenue interest in this lease which has been producing since our acquisition in July 2002. This lease was acquired from Bass Petroleum, Inc., an unaffiliated company, for a cash payment of $735,000. This lease has approximately 2,120 acres and seven producing wells. We believe up to five additional locations may be suitable for drilling, which are included in our estimate of our PUD. This lease is held by production.
Eva South Morrow Sand Unit – Texas County, Oklahoma. We own a 100% working interest and an 85.41% net revenue interest in this lease which was also acquired in July 2002. This lease was acquired from Ensign Operating Company, an unaffiliated company, for a cash payment of $827,500. The lease consists of approximately 489 acres and has seven producing wells, with a possibility for two additional wells, which have been included in our estimate of our PUD. This lease is held by production.
Midwell, Appleby, Smaltz and Hanes Leases – Cimarron County, Oklahoma. We own 100% of the working interest and an 80% net revenue interest in these four leases acquired in September 2002. All have been producing leases since the date of our acquisition. The Midwell Appleby and Smaltz leases consist of approximately 1,640 acres with 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. All of these leases are held by production.
Roy Hanes Lease – Texas County, Oklahoma. We own a 24.5% working interest and a 21.44% net revenue interest in this lease, which is a property operated by XTO Energy, Inc, an unaffiliated company, who also owns the remaining working interest. The interest in this lease was acquired at the same time we acquired our interests in the Midwell, Appleby, Smaltz and Hanes leases, and there has been production on this lease since that time. This lease consists of approximately 640 acres, and is currently held by production.
The Midwell, Appleby, Smaltz, Hanes and Roy Hanes leases were acquired from Burk Royalty Co., Ltd. R.A. Kimball Property Co., Ltd. and Kimball Family Resources, Ltd., all unaffiliated companies. The cost of these leases was $550,179, with $100,000 paid in cash and the balance paid through our issuance of 99,885 shares of our common stock valued at $4.00 per share (the then current market value), and the issuance of put and call options with a net value to the sellers of $50,639.
Significant Kansas Operations
Koehn/Rexford Unit – Haskell & Gray County, Kansas. This lease consists of approximately 640 acres. After entering into a farmout agreement with Bird Creek Resources, Inc., an unaffiliated company, we drilled and completed an initial gas well on this lease. Under the terms of this agreement, we agreed to drill one well and could drill additional wells on the property. In exchange for each well drilled, we will be assigned 100% of the working interest (80% of the net revenue interest) in the well and related oil and gas until payout of all costs of drilling, equipping and operating the well. After payout, our working interest in the wells and related oil and gas will decrease to 75% (60% of the net revenue interest).
In 2002, we successfully drilled one well at a cost of approximately $153,000 to drill, complete and connect to the pipeline and thus will have reached payout when we recover this amount from production. After payout, Bird Creek Resources, Inc. will own the remaining 25% working interest.
On March 20, 2002, we entered into a joint venture agreement with Petro Consultants, Inc., to drill and operate the well on the above-mentioned property. Under the terms of the agreement, Petro purchased 27% of the working interest in the well for $88,200. On May 20, 2002, after the well was successfully drilled, we issued 70,000 shares of common stock (valued at $1.26 per share) to Petro to repurchase the 27% working interest in the well.
In February 2004, we successfully drilled one additional well on this acreage at a cost of approximately $159,000 to drill, complete and connect to the pipeline and thus will have reached payout when we recover this amount from production. After payout, Bird Creek Resources, Inc. will own the remaining 25% working interest.
In November 2004, we completed the installation of a pipeline from our Koehn lease to a gatherer/purchased pipeline. Total cost on installation of the pipeline was approximately $144,000. The installation of this pipeline was necessary to be able to begin producing from our wells in that area. Production started on December 11, 2004.
Schmidt Unit – Gray County, Kansas. During 2004 we leased an additional 640 acres offsetting our Koehn/Rexford Unit for a total of approximately $8,582. In November 2004, we successfully drilled one well on this acreage at a cost of approximately $183,520 to drill, complete and connect to the pipeline. We began producing from this well on December 23, 2004.
Beals Prospect – Comanche County, Kansas. In July 2003 we acquired a 100% working interest and an 80.5% net revenue interest in this lease, consisting of 1,560 acres. This lease was acquired from Bengalia Land and Cattle Company., an unaffiliated party, for a cash payment of $60,000. During August 2003 we drilled one well on this acreage, which was unsuccessful and was plugged and abandoned. This lease will expire in April 2006 if not then held by production.
The following table summarizes gross and net developed and undeveloped acreage at December 31, 2004 by region (net acreage is our percentage ownership of gross acreage). Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.
| Developed Acreage | Undeveloped Acreage | Total Acreage | |||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||
| New Mexico | 4,960 | 3,294 | -- | -- | 4,960 | 3,294 | |||||
| Texas | 14,767 | 11,251 | -- | -- | 14,767 | 11,251 | |||||
| Oklahoma | 5,689 | 4,242 | -- | -- | 5,689 | 4,242 | |||||
| Kansas | 1,280 | 1,024 | 1,560 | 1,256 | 2,840 | 2,280 | |||||
| Total | 26,696 | 19,811 | 1,560 | 1,256 | 28,256 | 21,067 | |||||
The following table presents the historical information about our produced natural gas and oil volumes.
| Year Ended December 31, | |||||||||||
| 2002 | 2003 | 2004 | |||||||||
| Oil production (Bbls) | 58,717 | 117,646 | 195,166 | ||||||||
| Natural gas production (Mcf) | 46,819 | 67,329 | 169,002 | ||||||||
| Total production (Boe) | 66,520 | 128,868 | 223,333 | ||||||||
| Daily production (Boe/d) | 182 | 353 | 612 | ||||||||
| Average sales price: | |||||||||||
| Oil (per Bbl) | $ | 26.09 | $ | 29.06 | $ | 39.25 | |||||
| Natural gas (per Mcf) | 2.67 | 3.67 | 4.86 | ||||||||
| Total (per Boe) | 24.91 | 28.44 | 37.98 | ||||||||
| Average production cost (per Boe) | $ | 8.94 | $ | 8.92 | $ | 8.85 | |||||
The average oil sales price amounts above are calculated by dividing revenue from oil sales by the volume of oil sold, in Bbl. The average gas sales price amounts above are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The total average sales price amounts are calculated by dividing total revenues by total volume sold, in Boe. The average production costs above are calculated by dividing production costs by total production in Boe.
The following table presents our ownership at December 31, 2004, in productive oil and natural gas wells by region (a net well is our percentage ownership of a gross well).
| Oil Wells | Gas wells | Total Wells | |||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||
| New Mexico | 93 | 60 | - | - | 93 | 60 | |||||
| Texas | 182 | 138 | - | - | 182 | 138 | |||||
| Oklahoma | 23 | 19 | - | - | 23 | 19 | |||||
| Kansas | - | - | 3 | 2 | 3 | 2 | |||||
| Total | 298 | 217 | 3 | 2 | 301 | 219 | |||||
During 2004 we completed the drilling of nine wells, completed a wash down on one well and had contracted for the drilling of one additional well that was not commenced until January 2005. Two of the wells were drilled and completed in Gray County, Kansas, offsetting the Koehn well that was drilled in 2002. Both of these wells were placed into production in December 2004. The third newly drilled well is on our Dodson property in Montague County, Texas. This well has been completed but has not yet been placed into production. The remaining six newly drilled wells and the one washed down well are in on our East Hobbs San Andres Unit property in Lea County, New Mexico. All seven wells were completed have been placed into production. The well for which we had contracted for drilling that was commenced in January 2005 is on our West San Andres Unit property in Yoakum County, Texas. This well was drilled in January 2005 and completed in March 2005, but has not yet been placed into production.
We conduct our oil and natural gas activities entirely in the United States. As noted previously in the table appearing under “Production History”, our average production costs, per Boe, were $8.94 in 2002, $8.92 in 2003 and $8.85 in 2004. These amounts are calculated by dividing our total production costs by our total volume sold, in Boe.
Costs incurred for property acquisition, exploration and development activities during the years ended December 31, 2002, 2003 and 2004 are shown below.
| For the Years Ended December 31, | |||||||||||
| 2002 | 2003 | 2004 | |||||||||
| Acquisition of proved properties | $ | 2,659,832 | $ | 2,692,039 | $ | 21,706,166 | |||||
| Acquisition of unproved properties | - | 147,000 | 43,082 | ||||||||
| Exploration costs | - | 326,410 | 216,805 | ||||||||
| Development costs | 579,153 | 849,864 | 4,027,754 | ||||||||
| Total Costs Incurred | $ | 3,238,985 | $ | 4,015,313 | $ | 25,993,807 | |||||
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, 2001 | 494,823 | 2,960,373 | ||
| Purchase of minerals in place | 3,597,156 | 1,676,706 | ||
| Extensions and discoveries | -- | -- | ||
| Production | (58,717) | (46,819) | ||
| Revisions of estimates | 80,674 | (1,402,503) | ||
| Balance, December 31, 2002 | 4,113,936 | 3,187,757 | ||
| Purchase of minerals in place | 3,175,357 | 570,924 | ||
| Extensions and discoveries | 18,066 | 229,626 | ||
| Production | (117,646) | (67,329) | ||
| Revisions of estimates | (139,546) | (512,224) | ||
| Balance, December 31, 2003 | 7,050,167 | 3,408,754 | ||
| Purchase of minerals in place | 8,764,087 | 6,431,437 | ||
| Extensions and discoveries | - | 640,000 | ||
| Production | (195,167) | (169,002) | ||
| Revisions of estimates | 3,931,577 | (311,648) | ||
| Balance, December 31, 2004 | 19,550,664 | 9,999,541 | ||
Our proved oil and natural gas reserves are shown below.
| For the Years Ended December 31, | ||||||||||||
| 2002 | 2003 | 2004 | ||||||||||
| Oil (Bbls) | ||||||||||||
| Developed | 750,463 | 1,580,521 | 4,721,293 | |||||||||
| Undeveloped | 3,363,473 | 5,469,646 | 14,829,371 | |||||||||
| Total | 4,113,936 | 7,050,167 | 19,550,664 | |||||||||
| Natural Gas (Mcf) | ||||||||||||
| Developed | 1,160,639 | 1,612,738 | 4,615,265 | |||||||||
| Undeveloped | 2,027,118 | 1,796,016 | 5,384,276 | |||||||||
| Total | 3,187,757 | 3,408,754 | 9,999,541 | |||||||||
| Total (Boe) | ||||||||||||
| Developed | 943,904 | 1,849,311 | 5,490,504 | |||||||||
| Undeveloped | 3,701,326 | 5,768,972 | 15,726,750 | |||||||||
| Total | 4,645,230 | 7,618,283 | 21,217,254 | |||||||||
Our standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and changes in the standardized measure as described below were prepared in accordance with the provisions of SFAS 69. Future cash inflows were computed by applying year-end prices to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in producing and developing the proved oil and natural gas reserves at year end, based on year-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are calculated by applying appropriate year-end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10 percent annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of our oil and natural gas properties.
The standardized measure of discounted future net cash flows relating to the proved oil and natural gas reserves are shown below.
| December 31, | 2003 | 2004 | |||||
| Future net cash inflows | $ | 218,026,254 | $ | 814,346,791 | |||
| Future production costs | (64,157,199) | (171,518,828) | |||||
| Future development costs | (13,609,384) | (61,975,106) | |||||
| Future income taxes | (45,778,941) | (187,392,403) | |||||
| Future net cash flows | 94,480,730 | 393,460,454 | |||||
| 10% annual discount for estimated timing of cash flows | (49,474,633) | (188,219,704) | |||||
| Standardized Measure of Discounted Future Net Cash Flows | $ | 45,006,097 | $ | 205,240,750 | |||
The changes in the standardized measure of discounted future net cash flows relating to the proved oil and natural gas reserves are shown below.
| For the Years Ended December 31, | |||||||
| 2003 | 2004 | ||||||
| Beginning of the year | $ | 27,997,824 | $ | 45,006,097 | |||
| Purchase of minerals in place | 21,333,720 | 142,824,938 | |||||
| Extensions, discoveries and improved recovery, less related costs | 691,469 | 347,652 | |||||
| Development costs incurred during the year | 320,102 | 5,387,638 | |||||
| Sales of oil and gas produced, net of production costs | (2,302,405) | (5,876,333) | |||||
| Accretion of discount | 3,012,793 | 4,882,064 | |||||
| Net change in prices and production costs | 8,222,075 | 74,777,221 | |||||
| Net change in estimated future development costs | 39,219 | (3,187,159) | |||||
| Revision of previous quantity estimates | (53,098) | 42,149,044 | |||||
| Revision of estimated timing of cash flows | (5,468,732) | (27,509,967) | |||||
| Net change in income taxes | (8,786,869) | (73,560,445) | |||||
| End of the Year | $ | 45,006,097 | $ | 205,240,750 | |||
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 26,696 gross (19,810 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, 2004, we owned interests in approximately 1,560 gross undeveloped acres (1,256 net). We believe that our current and future cash flow will enable us to undertake the exploitation of our properties through additional drilling activities. Our expected capital budget for development of existing properties in 2005 is approximately $15 million.
Pursuing Profitable Acquisitions. We have historically pursued acquisitions of properties that we believe to have exploitation and development potential comparable to our existing inventory of drilling locations. We have developed and refined an acquisition program designed to increase reserves and complement our existing core properties. We have an experienced team of management and engineering professionals who identify and evaluate acquisition opportunities, negotiate and close purchases and manage acquired properties. From August 2000 through December 31, 2004, we acquired 12 leases at an aggregate acquisition and enhancement cost of approximately $33 million, representing approximately 21.2 million Boe of proved reserves. While our emphasis in 2005 and beyond is anticipated to focus on the further development our existing properties, we will continue to look for properties with both existing cash flow from production and future development potential.
Controlling Costs through Efficient Operation of Existing Properties. We operate essentially 100% of the pre-tax PV10 value of our total proved reserves, which we believe enables us to better manage expenses, capital allocation and the decision-making processes related to our exploitation and exploration activities. For the year ended December 31, 2004, our oil and gas production costs per Boe averaged $8.90 and general and administrative costs averaged $3.02 per Boe produced.
We currently lease our principal executive offices in Tulsa, Oklahoma. At December 31, 2004, the lease was for approximately 2,352 square feet of office space, at an annual rental of $20,400. Subsequent to December 31, 2004 and effective March 1, 2005, we leased an additional 385 square feet of office space at the same location and extended the lease through January 1, 2006. Our annual rental for 2005 will be $24,400. The current facilities are believed adequate for our current operations.
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.
Our annual shareholders meeting was held on December 21, 2004. The shareholder’s re-elected Messrs. Stanley M. McCabe, Lloyd T. Rochford, Charles M. Crawford, Chris V. Kemendo, Jr. and Clayton E. Woodrum as Directors with terms ending in 2005. The shareholders further approved an amendment to the Company’s executive stock option plan to increase the number of shares of Common Stock that may be granted under the plan from 1,000,000 to 1,500,000, and to provide discretionary acceleration of vesting of options previously granted. Following is a chart reflecting the votes cast for each of the elected directors, as well as for the amendment to the stock option plan:
| Votes for | Votes against | Abstain | |||||||||
| Lloyd T. Rochford | 5,556,002 | - | 11,001 | ||||||||
| Stanley M. McCabe | 5,556,002 | - | 11,001 | ||||||||
| Charles M. Crawford | 5,556,002 | - | 11,001 | ||||||||
| Chris V. Kemendo, Jr. | 5,545,002 | - | 22,001 | ||||||||
| Clayton E. Woodrum | 5,556,002 | - | 11,001 | ||||||||
| Amendment to option plan | 5,473,992 | 93,011 | 438,038 |
| Item 5: | Market for Registrant’s Common Stock, Related Stockholder Matters and Issuer Purchases of Equity Securities |
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 2003 | $ | 4.35 | $ | 4.25 | |||
| 2nd Quarter 2003 | 5.99 | 4.35 | |||||
| 3rd Quarter 2003 | 5.82 | 5.45 | |||||
| 4th Quarter 2003 | 6.10 | 5.40 | |||||
| 1st Quarter 2004 | $ | 7.08 | $ | 5.85 | |||
| 2nd Quarter 2004 | 9.65 | 6.98 | |||||
| 3rd Quarter 2004 | 7.46 | 5.98 | |||||
| 4th Quarter 2004 | 8.79 | 6.80 | |||||
| 1st Quarter 2005 (through March 10, 2005) |
$ | 13.40 | $ | 8.35 |
As of March 1, 2005, there are approximately 1,481 holders of record of our common stock. Approximately 24%, or 2,430,200 shares of the 10,194,304 shares issued and outstanding as of such date are held by management or affiliated parties.
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.
In March 2003, our board of directors adopted an executive stock option plan which was subsequently approved by our shareholders at our annual meeting in July 2003, and which was amended by our shareholders at our annual meeting in 2004. Information regarding this plan and the options that have been granted under this plan may be found in this Annual Report under Part III, Items 10 and 11.
Throughout 2004, we issued 78,300 shares of our common stock upon the exercise of previously issued warrants at either $1.75 per share or $5.00 per share. These shares were issued in a transaction not involving a public offering and were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act of 1933. The persons to whom the shares were issued had access to full information concerning us and represented that he acquired the shares for his own account and not for the purpose of distribution. The certificates for the shares contain a restrictive legend advising that the shares may not be offered for sale, sold or otherwise transferred without having first been registered under the 1933 Act or pursuant to an exemption from registration under the 1933 Act. There was no underwriter involved in these transactions.
In August 2004, we issued 25,000 shares of common stock valued at $5.99 per share and 15,000 shares of common stock valued at $6.00 per share, for a total of $239,750, as compensation to a consultant utilized in connection with our acquisition of the East Hobbs San Andres 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 December 2004, we issued 30,000 shares of common stock valued at $7.00 per share, or $210,000, as compensation to a consultant utilized in connection with our acquisition of the Fuhrman Mascho leases in Andrews 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.
We did not make any repurchases of our equity securities during the quarter ending December 31, 2004.
| Item 6: | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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.
We are engaged in oil and natural gas acquisition, exploration and exploitation activities in the states of Oklahoma, Texas, New Mexico and Kansas. Over the last four years, we have emphasized the acquisition of properties that provided current production and significant upside potential through further development.
We have increased our reserves significantly by investing approximately $25.4 million in acquisitions and enhancements in 2004, following total capital expenditures of approximately $4 million in 2003 and approximately $3.2 million in 2002.
Our capital budget for 2005 is approximately $15 million for development of existing properties. We also intend to continue seeking acquisition opportunities which compliment our current portfolio. We intend to fund our development activity primarily through use of cash flow from operations and cash on hand, while potential drawings on our credit facility and proceeds from future equity transactions would also be available for development projects or future acquisitions.
Our business plan has involved increasing our base of proven reserves until we have acquired a sufficient core to enable us to utilize cash from existing production to fund further development activities. When we originated our business plan we believed this would allow us to lessen our risks, including risks associated with borrowing funds to undertake exploration activities at an earlier time. As we have now increased our base of proven properties, and as oil and natural gas prices have recently significantly risen, we have initiated our development activities.
While our focus has shifted to include more development activity, we plan to continue our strategy of acquiring producing properties with additional development, exploitation and exploration potential. Our focus has been on acquiring operated properties (i.e. properties with respect to which we serve as the operator on behalf of all joint interest owners) so that we can better control the timing and implementation of capital spending. In 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 satisfy our general business plan. In addition, our willingness to acquire non-operated properties in new geographic regions may provide us with geophysical and geologic data in some cases that leads to further acquisitions in the same region, whether on an operated or non-operated basis.
Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.
In a worst case scenario, future drilling operations could be largely unsuccessful, oil and gas prices could sharply decline and/or other factors beyond our control could cause us to greatly modify or substantially curtail our development plans, which could negatively impact our earnings, cash flow and most likely the trading price of our securities, as well as the acceleration of debt repayment and a reduction in our borrowing base under our credit facilities.
The following table sets forth selected operating data for the periods indicated:
| For the Years Ended December 31, | ||||||||||||
| 2002 | 2003 | 2004 | ||||||||||
| Net production: | ||||||||||||
| Oil (Bbls) | 58,717 | 117,646 | 195,116 | |||||||||
| Natural gas (Mcf) | 46,819 | 67,329 | 169,002 | |||||||||
| Net sales: | ||||||||||||
| Oil | $ | 1,532,045 | $ | 3,418,480 | $ | 7,661,006 | ||||||
| Natural gas | 124,992 | 246,997 | 821,124 | |||||||||
| Average sales price: | ||||||||||||
| Oil (per Bbl) | $ | 26.09 | $ | 29.06 | $ | 39.25 | ||||||
| Natural gas (per Mcf) | 2.67 | 3.67 | 4.86 | |||||||||
| Production costs and expenses | ||||||||||||
| Lease operating expenses | $ | 594,863 | $ | 1,149,136 | $ | 1,975,835 | ||||||
| Production taxes | 117,164 | 269,563 | 629,703 | |||||||||
| Depreciation, depletion and amortization expense |
151,197 | 360,282 | 1,011,602 | |||||||||
| General and administrative expenses |
248,018 | 778,774 | 874,850 | |||||||||
Restatement of Financial Statements to Reflect Compensation Related to Stock Option Grants
In late 2005, following discussions with our independent auditors, we decided to restate our financial statements for the years ended December 31, 2003 and December 31, 2004, to reflect a change in how we account for compensation expenses associated with options granted to employees and to record an adjusted value (adjusted to market value on the date of issuance) of 40,000 shares of the Company’s common stock which were originally issued as a “finders fee” in connection with the acquisition of property and capitalized as part of properties subject to amortization. The first change essentially results in our recognition of compensation expense related to the discount amount of the exercise price of the option from the market price of the stock at the date of grant over the vesting period. The discount on all options granted through December 31, 2004 has been 15%, and the vesting period has been five years. The second change results in an additional $35,217 in value attributable to properties subject to amortization. The result of these changes is that general and administrative expenses (which include our current compensation expenses) have increased, with a resulting reduction in our net income after taxes for each year. The effect of this change on our net income after taxes is to reduce our net income for the year ended December 31, 2003 by $139,355 (from $809,498 to $670,143), which equates to a reduction in our earnings per share from $0.12 to $0.10 for basic earnings per share and from $0.11 to $0.09 for diluted earnings per share, and for the year ended December 31, 2004 by $128,365 (from $2,580,017 to $2,451,652), which equates to a reduction in our earnings per share from $0.33 to $0.31 for basic earnings per share and from $0.30 to $0.28 for diluted earnings per share. The comparisons reflected in the following discussions under “General and administrative expenses” and “Net income”, reflect the effect of such restatement. The addition of $35,217 in value attributable to properties subject to amortization had no impact on our amortization expenses or net income as reported for these periods.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Oil and natural gas sales. Oil and natural gas sales revenue increased approximately $4.82 million to $8.48 million in 2004. Oil sales increased $4.42 million and natural gas sales increased $575,000. The oil sales increase was caused by a sales volume increase of 77,470 barrels in 2004, and a 35% increase in the average realized per barrel oil price from $29.06 in 2003 to $39.25 in 2004. These per barrel amounts are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels. The natural gas sales increase was caused by a sales volume increase of 101,673 Mcf in 2004 and a 32% increase in the average realized natural gas price per Mcf from $3.67 in 2003 to $4.86 in 2004. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The volume increase for crude oil and natural gas primarily resulted from $26 million of capital expenditures during 2004, of which approximately $21 million were related to our acquisition of the East Hobbs and Fuhrman Mascho properties.
Oil and gas production costs. Our aggregate oil and gas production costs increased from $1,149,136 in 2003 to $1,975,835 2004, although such expenses on a Boe basis declined slightly from $8.92 in 2003 to $8.85 in 2004. These per Boe amounts are calculated by dividing out total production costs by our total volume sold, in Boe. This aggregate increase was the result of having the properties acquired in 2003 in our operations for a full year in 2004; acquiring new properties and accounting for them for a portion of the year in 2004 and cost increases. The decline on a per Boe basis is attributable to consolidation of resources available due to our growth.
Oil and gas production taxes. Oil and gas production taxes as a percentage of oil and natural gas sales were 7% during 2003 and remained steady at 7% in 2004. Production taxes vary from state to state. Therefore, these taxes are likely to vary in the future depending on the mix of production we generate from various states, and on the possibility that any state may raise its production tax.
Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased by $651,320 to $1,011,602 in 2004. The increase was a result of an increase in the average depreciation, depletion and amortization rate from $2.79 per Boe during 2003 to $4.53 per Boe during 2004. These per Boe amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total volume sold, in Boe. The increased depreciation, depletion and amortization was the result of increased sales volume and an increase in estimated future development costs.
General and administrative expenses. General and administrative expenses increased by $96,076 to $874,850 during 2004. This increase was primarily related to increases in compensation expense associated with an increase in personnel required to administer our growth, legal fees of $31,150, annual listing fees of $18,700, $16,095 in fees paid to Lee Keeling for 2003 reserve reports, fees related to obtaining our credit facility and letters of credit and directors fees.
Interest expense. Interest expense increased $117,138 to $155,936 in 2004. The increase was due to higher amounts of debt being outstanding during periods of the year in 2004.
Income tax expense. Our effective tax rate was 37% during 2004 and 37% during 2003.
Cumulative change in accounting principle. Effective January 1, 2003, we adopted the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.” This statement generally applies to legal obligations associated with the retirement of long-lived assets and requires us to recognize the fair value of asset retirement obligations in our financial statements by capitalizing that cost as a part of the cost of the related asset. This statement applies directly to the plug and abandonment liabilities associated with our net working interest in well bores. The additional carrying amount is depleted over the estimated lives of the properties. The discounted liability is based on historical abandonment costs in specific areas and is accreted at the end of each accounting period through charges to accretion expense. The liability is discounted using a credit-adjusted risk-free rate of approximately 8.08%. If the obligation is settled for other than the carrying amount, a gain or loss is recognized on settlement. Upon adoption of SFAS No. 143, we recorded an increase to our discounted abandonment liability of $236,718, increased proved property cost by $217,878, and recognized a one-time cumulative effect charge of $11,813 (net of a related tax effect of $7,027). The effect of adopting this accounting principle was a $24,873 after tax decrease in net income during 2003.
Net income. Net income increased from $670,143 for 2003 to $2,451,652 for 2004. The primary reasons for this increase include higher crude oil and natural gas prices between periods and an increase in volumes sold, partially offset by higher oil and gas production costs, oil and gas production taxes and general and administrative expenses due to our growth.
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 58,929 barrels in 2003, and a 11% increase in the average realized per barrel oil price from $26.09 in 2002 to $29.06 in 2003. These per barrel amounts are calculated by dividing revenue from oil sales by the volume of oil sold, in barrels. The natural gas sales increase was caused by a sales volume increase of 20,510 Mcf in 2003 and a 37% increase in the average realized natural gas price per Mcf from $2.67 in 2002 to $3.67 in 2003. These per Mcf amounts are calculated by dividing revenue from gas sales by the volume of gas sold, in Mcf. The volume increase for crude oil and natural gas primarily resulted from $3 million of capital expenditures during 2003.
Oil and gas production costs. Our aggregate oil and gas production costs increased from $594,863 or $8.94 per Boe in 2002 to $1,149,136 or $8.92 per Boe in 2003, although such expenses on a per Boe basis declined slightly from $8.94 in 2002 to $8.92 in 2003. These per Boe amounts are calculated by dividing out total production costs by our total volume sold, in Boe. This aggregate increase was a result of higher operating costs on properties acquired in 2003. The decline on a per Boe basis is attributable to consolidation of resources available due to our growth. 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.
Oil and gas production taxes. Oil and gas 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 $209,085 to $360,282 in 2003. The increase was a result of an increase in the average depreciation, depletion and amortization rate from $2.27 per Boe during 2002 to $2.79 per Boe during 2003. These per Boe amounts are calculated by dividing our total depreciation, depletion and amortization expense by our total volume sold, in Boe. The increased depreciation, depletion and amortization was the result of increased sales volume and an increase in estimated future development costs.
General and administrative expenses. General and administrative expenses increased by $530,756 to $778,774 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), the amortization of the deferred compensation associated with the outstanding stock options of $221,198, 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 $24,873 after tax decrease in net income during 2003.
Net income. Net income increased from $387,049 for 2002 before preferred stock dividends, to $670,143 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 oil and gas production costs, oil and gas production taxes and general and administrative expenses due to our growth.
Historical Financing. We have historically funded our operations through loans from our executive officers, our initial public offering of stock in 2001, private equity offerings of our stock and warrants and our Secondary offering of common stock and warrants which we closed in August 2004.
Credit Facility. On April 14, 2004, we established a new $15,000,000 credit facility with our principal lenders with an $8,500,000 initial borrowing base. In November 2004, we entered into an agreement that increased the facility to $25,000,000, with an increased borrowing base of $15,000,000. Any increases in the borrowing base are subject to written consent by the financial institution. The interest rate is a floating rate equal to the 30, 60 or 90 day LIBOR rate plus 2.25%, currently 5.04% per annum, and is payable monthly. Annual fees for the facility are 1/8 of one percent of the unused portion of the borrowing base. Amounts borrowed under the revolving credit facility are due in April 2007. The revolving credit facility is secured by our principal mineral interests. In order to obtain the revolving credit facility, loans from two officers were subordinated to the position of the bank. We are required under the terms of the credit facility to maintain a tangible net worth of $12,000,000, maintain a 5-to-1 ratio of income before interest, taxes, depreciation, depletion and amortization to interest expense and maintain a current asset to current liability ratio of 1-to-1, not including the $2,000,000 bridge financing arrangement discussed below. On May 7, 2004, we drew $8,008,440 under this revolving credit facility to fund the acquisition of the East Hobbs San Andres Property interests. During August 2004, utilizing cash flow from operations and proceeds from the recent secondary offering of common stock and warrants, we paid $8,008,440 of principal and related accrued interest due on the credit facility. During December 2004, we drew $9,000,000 under this revolving credit facility to fund the acquisition of the Fuhrman Mascho leases and $1,000,000 to help fund development activities. An additional $299,029 is reserved under the revolving credit facility as collateral for standby letters of credit issued to various states.
On April 14, 2004, we also entered into to a bridge financing arrangement for $2,000,000 from our lender. On April 21, 2004, we borrowed $1,000,000 under the terms of the bridge financing agreement to fund a cash deposit made on the East Hobbs San Andres Property interests. On May 7, 2004, we borrowed an additional $1,000,000 under the terms of the bridge financing arrangement to fund the acquisition of the East Hobbs San Andres Property interests. The interest rate on the bridge financing arrangement is a floating rate equal to the 30, 60 or 90 day LIBOR rate plus 2.25%, currently 3.42% per annum, and is payable monthly. This arrangement was established for a one-time purpose to satisfy the funding requirements of the East Hobbs San Andres Property acquisition. The original agreement expired June 30, 2004 and was subsequently extended to July 31, 2004. The bridge financing arrangement was guaranteed by two of the Company’s officers. During August 2004, utilizing cash flow from operations and proceeds from the recent public offering of common stock and warrants, the Company paid $2,000,000 of principal and related accrued interest due under the bridge financing agreement. Since repayment in August 2004, no amounts have been outstanding on this bridge financing agreement and no new agreements have been established to continue the bridge financing arrangement.
Cash Flows. Our primary sources of cash have been cash flows from operations and equity offerings. During the three years ended December 31, 2004, we generated $7,572,898 from operating activities, financed $14,230,863 through proceeds from the sale of stock and warrants, and $400,000 from debt obligations owed to two officers, for a total of $22,203,761. We primarily used this cash generation to fund our capital expenditures aggregating $31,385,738 over the three years. At December 31, 2004, we had $1,253,969 of cash and $772,154 of working capital compared to December 31, 2003 when our cash position was $1,076,676 and working capital was $1,268,888.
We continually evaluate our capital needs and compare them to our capital resources. Our budgeted capital expenditures for 2005 are approximately $15,000,000 for development of our current properties. We expect to fund these expenditures as well as any future property acquisitions from cash on hand, internally generated cash flow during the year 2005, proceeds from future equity transactions and from borrowings under our credit facility, if required. The level of capital expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among others.
Schedule of Contractual Obligations. The following table summarizes our future estimated principal and minimum debt and lease payments for periods subsequent to December 31, 2004.
| Year | Long-Term Debt | Lease Obligation | Total Cash Obligation | ||||||||
| 2005 | $ | - | $ | 24,400 | $ | 24,400 | |||||
| 2006 | 400,000 | - | 400,000 | ||||||||
| 2007 | 10,000,000 | - | 10,000,000 | ||||||||
| Total | $ | 10,400,000 | $ | 24,400 | $ | 10,424,400 | |||||
As of December 31, 2004 we had no off-balance sheet financing arrangements.
Effective January 1, 2003, we adopted the provisions of SFAS No. 143, “Accounting for Asset Retirement Obligations.” This statement generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 requires us to recognize the fair value of asset retirement obligations in our financial statements by capitalizing that cost as a part of the cost of the related asset. In regards to us, this statement applies directly to the plug and abandonment liabilities associated with our net working interest in well bores. The additional carrying amount is depleted over the estimated lives of the properties. The discounted liability is based on historical abandonment costs in specific areas and is accreted at the end of each accounting period through charges to accretion expense. The liability is discounted using a credit-adjusted risk-free rate of approximately 8.08%. If the obligation is settled for other than the carrying amount, a gain or loss is recognized on settlement. Upon adoption of SFAS No. 143, we recorded an increase to our discounted abandonment liability of $236,718, increased property and equipment cost by $217,878 and recognized a one-time cumulative effect charge of $11,813 (net of a deferred tax benefit of $7,027).
The adoption of SFAS No. 143 also affected the depreciation, depletion and amortization on an on-going basis. The additionally capitalized amount for the discounted abandonment liability increases the base amount used in calculating depletion. This effect was an increase in depreciation, depletion and amortization for the years ended December 31, 2003 and 2004 of $7,459 and $10,798, respectively. The adoption of SFAS No. 143 also impacted the way the ceiling test is calculated under the full cost accounting method used by the Company, in that an estimation of future abandonment costs are now excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation. However, these costs are now part of the base amount, so while the way the calculation is performed has changed, the end result remains the same There were no option impacts of the adoption of SFAS No. 143.
In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities. This interpretation establishes the requirement for a primary beneficiary to consolidate certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. We do not have an interest in a variable interest entity and the adoption of the statement did not have an impact on our financial statements.
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This statement was effective for us in July 2003. The statement requires financial instruments to be classified as liabilities if the financial instruments are issued in the form of shares that are mandatorily redeemable or embody an obligation to repurchase equity shares. We issued a put option in exchange for oil and gas property interests in December 2004. The put option was originally classified as a liability; therefore, the adoption of the statement did not have an impact on our financial statements.
Our discussion of financial condition and results of operations is based upon the information reported in our financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors. Our significant accounting policies are detailed in Note 1 to our financial statements included in this Annual Report. We have outlined below certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by our management.
Revenue Recognition. We predominantly derive our revenue from the sale of produced crude oil and natural gas. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimated revenue and actual payment are recorded in the month the payment is received; however, differences have been insignificant.
Full Cost Method of Accounting. We account for our oil and natural gas operations using the full cost method of accounting. Under this method, all costs associated with property acquisition, exploration and development of oil and gas reserves are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and cost of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. All of our properties are located within the continental United States.
Oil and Natural Gas Reserve Quantities. Reserve quantities and the related estimates of future net cash flows affect our periodic calculations of depletion and impairment of our oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. Reserve quantities and future cash flows included in this Annual Report are prepared in accordance with guidelines established by the SEC and FASB. The accuracy of our reserve estimates is a function of:
| • | the quality and quantity of available date; |
| • | the interpretation of that data; |
| • | the accuracy of various mandated economic assumptions; and |
| • | the judgments of the persons preparing the estimates. |
Our proved reserve information included in this Annual Report is based on estimates prepared by Lee Keeling and Associates, Inc., independent petroleum engineers. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. We continually make revisions to reserve estimates throughout the year as additional properties are acquired. We make changes to depletion rates and impairment calculations in the same period that changes to the reserve estimates are made.
All capitalized costs of oil and gas properties, including estimated future costs to develop proved reserves and estimated future costs of site restoration, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent engineers. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined.
Impairment of Oil and Natural Gas Properties. We review the value of our oil and natural gas properties whenever management judges that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. We provide for impairments on undeveloped property when we determine that the property will not be developed or a permanent impairment in value has occurred. Impairments of proved producing properties are calculated by comparing future net undiscounted cash flows on a field-by-field basis using escalated prices to the net recorded book cost at the end of each period. If the net capitalized cost exceeds net future cash flows, the cost of the property is written down to “fair value,” which is determined using net discounted future cash flows from the producing property. Different pricing assumptions or discount rates could result in a different calculated impairment. We have never recorded any property impairments.
Income Taxes. We provide for income taxes in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes.” Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to actual in the period we file our tax returns.
While we did not experience any significant increased costs during 2003 due to increased demand for oil field products and services, this trend did not continue in 2004. The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs, and this proved to be the case in 2004 as oil and gas prices rose significantly. Costs for oilfield services and materials increased during 2004 due to higher demand as a result of the higher oil and gas prices. Material changes in prices impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans and value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate the increased business costs will continue while the commodity prices for oil and natural gas, and the demand for services related to production and exploration, both remain high (from an historical context) in the near term.
Commodity Price Risk
We have not historically entered into derivative contracts to manage our exposure to oil and natural gas price volatility. Normal hedging arrangements have the effect of locking in for specified periods the prices we would receive for the volumes and commodity to which the hedge relates. Consequently, while hedges are designed to decrease exposure to price decreases, they also have the effect of limiting the benefit of price increases.
Interest Rate Risk
Our current credit facility has a floating interest rate. Therefore, as a result of our draws on this credit facility, interest rate changes will impact future results of operations and cash flows.
| Item 7: | Financial Statements |
The financial statements and supplementary data required by this item are included at page 43.
| 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 submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. As of the end of the fiscal year ended December 31, 2004, our chief executive officer and chief financial officer evaluated the effectiveness of our disclosure controls and procedures. Based upon their evaluation of those controls and procedures, the chief executive officer and the principal financial officer of the Company concluded that as of the end of such period our disclosure controls and procedures are effective in alerting them to material information that is required to be included in the reports we file or submit under the Securities Exchange Act of 1934.
We made no change in our internal control over financial reporting during our fiscal year ended December 31, 2004 that has materially affected, or is reasonably likely to materially affect our internal control over financial reporting.
| Item 8B: | Other Information |
None
| Item 9: | Directors and Executive Officers |
The following table sets forth information regarding our executive officers, certain other officers and directors as of December 31, 2004:
| Name | Age | Position |
| Lloyd T. Rochford | 58 | President and Chief Executive Officer and Director |
| Stanley M. McCabe | 72 | Chairman of the Board of Directors, Secretary and Treasurer |
| William R. Broaddrick | 27 | Vice President and Chief Financial Officer |
| Charles M. Crawford | 52 | Director |
| Chris V. Kemendo, Jr. | 83 | Director |
| Clayton E. Woodrum | 64 | Director |
Each of the directors identified above were elected for a term of one year (or until their successors are elected and qualified) at our annual meeting of shareholders in December 2004.
Messrs. Rochford, McCabe and Crawford have served as directors since our inception in August 2000. Mr. Kemendo was first elected to the Board of Directors in February 2003 and Mr. Woodrum was initially appointed in August 2003 by the Board of Directors to fill a vacancy created upon the resignation of a director.
The following biographies describe the business experience of our executive officers and directors:
Mr. Rochford, 58, 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.
Stanley M. McCabe – Chairman of the Board of Directors, Secretary and Treasurer.
Mr. McCabe, 72, 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.
Mr. Broaddrick, 27, 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.
Mr. Crawford, 52, 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.
Mr. Kemendo, 83, 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 and compensation 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.
Mr. Woodrum, 64, 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.
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 2005 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.
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 (see the biographical information for each of Messrs. Kemendo and Woodrum, infra, in this discussion of “Directors and Executive Officers.)” Each of Messrs. Kemendo and Woodrum further qualifies as “independent” in accordance with the applicable regulations adopted by the SEC and American Stock Exchange.
Our board of directors has established a compensation committee, whose principal function is to make recommendations regarding the compensation of the Company’s officers. In accordance with the rules of the American Stock Exchange (on which our shares are listed), the compensation of our chief executive officer is recommended to the Board (in a proceeding in which the chief executive officer does not participate) by the compensation committee. The compensation committee is comprised of two independent directors, consisting of Messrs. Kemendo and Woodrum, with Mr. Kemendo acting as the chairman. Compensation for all other officers is also recommended to the Board for determination, by the compensation committee.
We currently do not have a nominating committee. Instead, in accordance with the rules of the American Stock Exchange, the independent directors (currently, Messrs. Crawford, Kemendo and Woodrum) fulfill the role of a nominating committee. Since our inception in 2000, we have had only six directors, five of whom continue to serve at this time. On the only occasion when a vacancy occurred (following a resignation), the new director was unanimously approved by the remaining directors. Therefore, the Board has not felt it necessary to have a standing nominating committee to deal with its infrequent changes in membership. If and when future vacancies occur, the Board would consider director nominees recommended by shareholders, as well as director nominees recommended by a majority of the directors who are then independent. The board does not have a formal policy regarding the consideration of, procedures to be followed by, minimum requirements of or process for identifying or evaluation nominees recommended by security holders.
Our board may establish other committees from time to time to facilitate our management.
All outside directors are currently compensated with a stipend of $500 per month plus $500 for each directors meeting attended. No director receives a salary as a director.
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.
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.
We have adopted a code of ethics that applies to our principal executive officer, principal financial officer and principal accounting officer or persons performing similar functions (as well as its other employees and directors). The Company undertakes to provide any person without charge, upon request, a copy of such code of ethics. Requests may be directed to Arena Resources, Inc., 4920 S. Lewis Ave., Suite 107, Tulsa, Oklahoma 74105, attention William R. Broaddrick, or by calling (918) 747-6060.
| Item 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 |
2002 | $ 36,000 | $ - | $ - |
| 2003 | $ 36,000 | $ - | $229,742 | |
| 2004 | $ 36,000 | $ - | $ - | |
| Stanley M. McCabe Chairman of the Board |
2002 | $ 36,000 | $ - | $ - |
| 2003 | $ 36,000 | $ - | $229,742 | |
| 2004 | $ 36,000 | $ - | $ - | |
| William R. Broaddrick Vice President, Chief Financial Officer |
2002 | $ 45,000 | $ 6,000 | $ - |
| 2003 | $ 47,927 | $ - | $459,484 | |
| 2004 | $ 51,500 | $ 4,167 | $ - | |
(1)
Mr. Broaddrick’s salary for 2003 reflects a raise that occurred in mid-year
to increase his annual salary to $50,000. Mr. Broaddrick’s salary for 2004
reflects a raise that occurred during the year to increase his annual salary to
$54,000. There are no current plans to change any officers’ salary from
their level at December 31, 2004.
(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, 2004 was 3.8 years.
Equity Incentive Plan. In March 2003, our board of directors adopted an executive stock option plan which was subsequently approved by our shareholders at our annual meeting in July 2003 and further amended by our shareholders at our annual meeting in December 2004. 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 1,500,000 shares of common stock, subject to adjustment to reflect stock dividends and other capital changes, are available for granting of awards under the executive stock option plan. 1,000,000 of the shares available for grant under the plan have been reserved for issuance pursuant to options granted during 2003. No options to acquire shares were granted under the plan in 2004.
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, 2004 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 | 25,000/100,000 | $120,000/$480,000 |
| Stanley M. McCabe | 0 | 0 | 25,000/100,000 | $120,000/$480,000 |
| William R. Broaddrick | 0 | 0 | 50,000/200,000 | $240,000/$960,000 |
| Charles M. Crawford | 0 | 0 | 10,000/40,000 | $48,000/$192,000 |
| Chris V. Kemendo, Jr. | 0 | 0 | 10,000/40,000 | $48,000/$192,000 |
| Clayton E. Woodrum | 0 | 0 | 10,000/40,000 | $37,000/$148,000 |
| Phillip W. Terry | 0 | 0 | 50,000/200,000 | $240,000/$960,000 |
| Raymond H. Estep | 0 | 0 | 20,000/80,000 | $96,000/$384,000 |
The following table sets forth information concerning our executive stock option plan as of December 31, 2004.
| Number of securities to be issued upon exercise of outstanding options |
Weighted- average exercise price of outstanding options |
Number of securities remaining available for future issuance under compensation plans (excluding securities in column (a)) |
|
| (a) | (b) | (c) | |
| Equity compensation plans approved by security holders |
1,000,000 | 3.76 | 500,000 |
| Equity compensation plans not approved by security holders |
- | - | - |
| Total | 1,000,000 | 3.76 | 500,000 |
| Item 11: | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The following table sets forth, as March 10, 2005, information regarding the beneficial ownership of our common stock: (i) by each of our directors and executive officers; (ii) by all directors and executive officers as a group; and (iii) by all persons known to us to own 5% or more of our outstanding shares of common stock. The mailing address for each of the persons indicated is our corporate headquarters.
Beneficial ownership is determined under the rules of the Securities and Exchange Commission. In general, these rules attribute beneficial ownership of securities to persons who possess sole or shared voting power and/or investment power with respect to those securities and includes, among other things, securities that an individual has the right to acquire within 60 days. Unless otherwise indicated, the stockholders identified in the following table have sole voting and investment power with respect to all shares shown as beneficially owned by them.
| Shares of Common Stock Beneficially Owned | |||||
|---|---|---|---|---|---|
| Name | Number | Percent | |||
| Lloyd T. Rochford | 1,262,600 (1) | 12% | |||
| Stanley M. McCabe | 1,263,000 (2) | 12% | |||
| William R. Broaddrick | 104,500 (3) | 1% | |||
| Charles M. Crawford | 20,000 (4) | * | |||
| Chris V. Kemendo, Jr | 20,100 (5) | * | |||
| Clayton E. Woodrum | 10,000 (6) | * | |||
| All directors and executive officers | 2,680,200 (7) | 26% | |||
| (1) | Includes 25,000 shares issuable upon the exercise of stock options that are currently exercisable and 25,000 shares issuable upon the exercise of stock options that are exercisable within 60 days. |
| (2) | Includes 25,000 shares issuable upon the exercise of stock options that are currently exercisable and 25,000 shares issuable upon the exercise of stock options that are exercisable within 60 days. |
| (3) | Includes 50,000 shares issuable upon the exercise of stock options that are currently exercisable and 50,000 shares issuable upon the exercise of stock options that are exercisable within 60 days. |
| (4) | Includes 10,000 shares issuable upon the exercise of stock options that are currently exercisable and 10,000 shares issuable upon the exercise of stock options that are exercisable within 60 days. |
| (5) | Includes 10,000 shares issuable upon the exercise of stock options that are currently exercisable and 10,000 shares issuable upon the exercise of stock options that are exercisable within 60 days. |
| (6) | Includes 10,000 shares issuable upon the exercise of stock options that are currently exercisable. |
| (7) | Includes 130,000 shares issuable upon the exercise of stock options that are currently exercisable and 120,000 shares issuable upon the exercise of stock options that are exercisable within 60 days by all executive officers and directors. |
| * | Represents beneficial ownership of less than 1% |
Percentage ownership calculations for any stockholder listed above are based on 10,194,304 shares of our common stock outstanding as of March 10, 2005.
| 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, 2006. 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).
In 2001 and 2002 we acquired certain lease interests and had other business dealings with Petro Consultants, Inc. One of the principals of Petro Consultants, Inc., Mr. Robert J. Morley, was appointed our Vice President of Investor Relations in July 2002 and served as a member of the Board of Directors from February 2003, until his resignation of all positions as an officer and director in August 2003. Therefore, any transactions involving Petro Consultant between July 2002 and August 2003 could be deemed to have been entered into with an “affiliate.” Because we anticipated that we may continue to transact business with Petro Consultants, to avoid future issues that might arise due to such affiliation, Mr. Morley resigned his position as an officer and member of our board and forfeited all stock options (none of which had vested) which he had been granted by reason of his position as a board member.
| Item 13: | Exhibits |
| 3.1 | Articles of Incorporation of Arena Resources, Inc. (i) |
| 3.2 | By-Laws of Arena Resources, Inc. (i) |
| 10.1 | Business Loan Agreement, dated as of April 14, 2004, among Arena Resources, Inc. and MidFirst Bank, N.A. (ii) |
| 10.2 | Business Loan Agreement, dated as of May 7, 2004, among Arena Resources, Inc. and MidFirst Bank, N.A. (ii) |
| 10.3 | Business Loan Agreement, dated as of November 16, 2004, among Arena Resources, Inc. and MidFirst Bank, N.A. (iii) |
| 10.4 | East Hobbs Purchase and Sales Agreement Dated April 22, 2004 (ii) |
| 10.5 | Fuhrman-Mascho Purchase and Sales Agreements Dated December 1, 2004 (iii) |
| 23 | 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 Resources, Inc.‘s Form SB-1 filed January 2, 2001 (SEC File No. 333-46164).
(ii) Incorporated herein by reference to the exhibits to Arena Resources, Inc.‘s From 8-K filed May 18, 2004.
(iii) Incorporated herein by reference to the exhibits to Arena Resources’ Form 10-KSB filed March 17, 2005.
| Item 14: | Principal Accountant Fees and Services |
The firm of Hansen, Barnett & Maxwell, (“HBM”) has served as the Company’s independent auditors since 2000. The Board of Directors selected HBM as the independent auditors of the Company for the fiscal year ending December 31, 2004, and the Audit Committee has selected HBM to serve in the same capacity for the fiscal year ending December 31, 2005. The Audit Committee has adopted a policy that requires advance approval of all audit, audit-related, tax services and other services performed by the independent auditor.
Audit Fees. HBM billed the Company an aggregate of $37,000 and $25,521 for professional services rendered for the audit of the Company’s financial statements for the years ended December 31, 2004 and 2003, respectively, and its reviews of the Company’s financial statements included in its Form 10-QSB’s for the first three quarters of 2004 and 2003.
Audit Related Fees. In 2004, HBM was paid $78,998 for its services in connection with the review of the Company’s registration statement on Form SB-2 (which was filed with the SEC in 2004) and for the audit of the Fuhrman-Mascho property acquisition, and which are not included in the audit fees identified above).
Tax Fees. HBM billed the Company an aggregate of $3,000 and $750 for professional services rendered for tax compliance, tax advice and tax planning for the years ended December 31, 2004 and 2003.
All Other Fees. No other fees were billed by HBM to the Company during 2004 or 2003.
The Audit Committee of the Board of Directors has determined that the provision of services by HBM described above is compatible with maintaining HBM’s independence as the Company’s principal accountant.
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: February 15, 2006 | ||
| By: | /s/ Stanley McCabe | |
| Mr. Stanley McCabe | ||
| Treasurer, Secretary | ||
| Date: February 15, 2006 | ||
| By: | /s/ William R. Broaddrick | |
| Mr. William R. Broaddrick | ||
| Chief Financial Officer | ||
| Date: February 15, 2006 | ||
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
| By: | /s/ Lloyd T. Rochford | |
| Mr. Lloyd T. Rochford | ||
| Director | ||
| Date: February 15, 2006 | ||
| By: | /s/ Stanley McCabe | |
| Mr. Stanley McCabe | ||
| Director | ||
| Date: February 15, 2006 | ||
| By: | /s/ Charles Crawford | |
| Mr. Charles Crawford | ||
| Director | ||
| Date: February 15, 2006 | ||
| By: | /s/ Chris V. Kemendo, Jr. | |
| Mr. Chris V. Kemendo, Jr. | ||
| Director | ||
| Date: February 15, 2006 | ||
| By: | /s/ Clayton E. Woodrum | |
| Mr. Clayton E. Woodrum | ||
| Director | ||
| Date: February 15, 2006 | ||
| Page | |
|---|---|
| Report of Independent Registered Public Accounting Firm | 44 |
| Balance Sheets - December 31, 2004 and 2003 | 45 |
| Statements of Operations for the Years Ended December 31, 2004 and 2003 | 46 |
| Statements of Stockholders' Equity for the Years Ended December 31, 2003 and 2004 | 47 |
| Statements of Cash Flows for the Years Ended December 31, 2004 and 2003 | 48 |
| Notes to Financial Statements | 50 |
| Supplemental Information on Oil and Gas Producing Activities | 64 |
| 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 |
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, 2004 and 2003, 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Arena Resources, Inc. as of December 31, 2004 and 2003, 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.
As discussed in Note 6 to the financial statements, the Company changed its method of recognizing asset retirement obligations in 2003. As discussed in Note 2, the accompanying financial statements have been restated to correct the valuation of common stock and stock options.
| HANSEN, BARNETT & MAXWELL |
Salt Lake City, Utah
January 14, 2005, except for Note 2
As
to which the date is December 21, 2005
ARENA RESOURCES, INC.
BALANCE SHEETS
(As Restated - Note 2)
| December 31, | 2004 | 2003 | |||
| ASSETS | |||||
| Current Assets | |||||
| Cash | $ | 1,253,969 | $ | 1,076,676 | |
| Account receivable | 1,149,513 | 388,910 | |||
| Joint interest billing receivable | 61,805 | - | |||
| Short-term investments | - | 25,234 | |||
| Prepaid expenses | 33,136 | 28,935 | |||
| Total Current Assets | 2,498,423 | 1,519,755 | |||
| Property and Equipment, Using Full Cost Accounting | |||||
| Oil and gas properties subject to amortization | 34,457,137 | 8,463,400 | |||
| Drilling advances | 900,000 | 351,000 | |||
| Equipment | 26,687 | 48,480 | |||
| Office equipment | 60,401 | 18,978 | |||
| Total Property and Equipment | 35,444,225 | 8,881,858 | |||
| Less: Accumulated depreciation and amortization | (1,565,124) | (559,229) | |||
| Net Property and Equipment | 33,879,101 | 8,322,629 | |||
| Deferred Offering Costs | - | 130,872 | |||
| Total Assets | $ | 36,377,524 | $ | 9,973,256 | |
| LIABILITIES AND STOCKHOLDERS' EQUITY | |||||
| Current Liabilities | |||||
| Accounts payable | $ | 1,805,865 | $ | 229,522 | |
| Accrued liabilities | 34,800 | 18,440 | |||
| Put option | - | 2,905 | |||
| Total Current Liabilities | 1,840,665 | 250,867 | |||
| Long-Term Liabilities | |||||
| Notes payable | 10,000,000 | - | |||
| Notes payable to related parties | 400,000 | 400,000 | |||
| Put option | 95,033 | - | |||
| Asset retirement liability | 1,267,993 | 607,200 | |||
| Deferred income taxes | 1,971,990 | 574,916 | |||
| Total Long-Term Liabilities | 13,735,016 | 1,582,116 | |||
| 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; 9,132,910 shares and 7,162,097 shares outstanding, respectively |
9,133 | 7,162 | |||
| Additional paid-in capital | 15,258,352 | 6,994,925 | |||
| Options and warrants outstanding | 3,213,159 | 1,473,164 | |||
| Deferred compensation | (234,277) | (438,802) | |||
| Retained earnings | 2,555,476 | 103,824 | |||
| Total Stockholders' Equity | 20,801,843 | 8,140,273 | |||
| Total Liabilities and Stockholders' Equity | $ | 36,377,524 | $ | 9,973,256 | |
The accompanying notes are an integral part of these financial statements.
ARENA RESOURCES, INC.
STATEMENTS OF OPERATIONS
(As Restated - Note 2)
| For the Years Ended December 31, | 2004 | 2003 | |||
| Oil and Gas Revenues | $ | 8,482,130 | $ | 3,665,477 | |
| Costs and Operating Expenses | |||||
| Oil and gas production costs | 1,975,835 | 1,149,136 | |||
| Oil and gas production taxes | 629,703 | 269,563 | |||
| Depreciation, depletion and amortization | 1,011,602 | 360,282 | |||
| General and administrative expense | 874,850 | 778,774 | |||
| Total Costs and Operating Expenses | 4,491,990 | 2,557,755 | |||
| Other Income (Expense) | |||||
| Gain from change in fair value of put options | 68,251 | 47,699 | |||
| Accretion expense | (53,729) | (32,212) | |||
| Interest expense | (155,936) | (38,798) | |||
| Net Other Income (Expense) | (141,414) | (23,311) | |||
| Income Before Provision for Income Taxes and Cumulative | |||||
| Effect of Change in Accounting Principle | 3,848,726 | 1,084,411 | |||
| Provision for Deferred Income Taxes | (1,397,074) | (402,455) | |||
| Income Before Cumulative Effect of Change | |||||
| in Accounting Principle | 2,451,652 | 681,956 | |||
| Cumulative Effect of Change in Accounting Principle | - | (11,813) | |||
| Net Income | $ | 2,451,652 | $ | 670,143 | |
| Basic Earnings Per Share | |||||
| Before cumulative effect of change in accounting principle | $ | 0.31 | $ | 0.10 | |
| Net Income | 0.31 | 0.10 | |||
| Diluted Earnings Per Share | |||||
| Before cumulative effect of change in accounting principle | $ | 0.28 | $ | 0.09 | |
| Net Income | 0.28 | 0.09 | |||
The accompanying notes are an integral part of these financial statements.
ARENA RESOURCES, INC.
STATEMENTS OF STOCKHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2003 AND 2004
(As Restated - Note 2)
| Common Stock | |||||||||||||
| Additional | Options and | Total | |||||||||||
| Shares | Amount | Paid-In Capital |
Warrants Outstanding |
Deferred Compensation |
Retained Earnings |
Stockholders' Equity |
|||||||
| Balance, December 31, 2002 | 6,282,056 | $ | 6,282 | $ | 5,287,189 | $ | 382,040 | $ | - | $ | (566,319) | $ | 5,109,192 |
| Issuance for cash | 790,294 | 790 | 1,274,256 | 436,154 | - | - | 1,711,200 | ||||||
| Issuance of employee stock options | - | - | - | 660,000 | (660,000) | - | - | ||||||
| Issuance of warrants as consulting fee | |||||||||||||
| for 2002 offering | - | - | (15,922) | 15,922 | - | - | - | ||||||
| Cancellation of shares for extension | |||||||||||||
| of lock up | (500) | - | - | - | - | - | - | ||||||
| Issuance of common stock for services | 13,847 | 14 | 75,026 | - | - | - | 75,040 | ||||||
| Warrants exercised | 19,400 | 19 | 54,883 | (20,952) | - | - | 33,950 | ||||||
| Issuance of common stock | |||||||||||||
| in property acquisitions | 57,000 | 57 | 319,493 | - | - | - | 319,550 | ||||||
| Amortization of deferred compensation | - | - | - | - | 221,198 | - | 221,198 | ||||||
| Net income | - | - | - | - | - | 670,143 | 670,143 | ||||||
| Balance, December 31, 2003 | 7,162,097 | 7,162 | 6,994,925 | 1,473,164 | (438,802) | 103,824 | 8,140,273 | ||||||
| Warrants exercised | 78,300 | 78 | 395,843 | (41,796) | - | - | 354,125 | ||||||
| Issuance for cash | 1,667,500 | 1,668 | 6,469,225 | 1,781,791 | - | - | 8,252,684 | ||||||
| Issuance of common stock in property | |||||||||||||
| acquisitions, net of call option received | 225,013 | 225 | 1,398,359 | - | - | - | 1,398,584 | ||||||
| Amortization of deferred compensation | - | - | - | - | 204,525 | - | 204,525 | ||||||
| Net income | - | - | - | - | - | 2,451,652 | 2,451,652 | ||||||
| Balance, December 31, 2004 | 9,132,910 | $ | 9,133 | $ | 15,258,352 | $ | 3,213,159 | $ | (234,277) | $ | 2,555,476 | $ | 20,801,843 |
The accompanying notes are an integral part of these financial statements.
ARENA RESOURCES, INC.
STATEMENTS OF CASH FLOWS
(As Restated - Note 2)
| For the Years Ended December 31 | 2004 | 2003 | |||
| Cash Flows From Operating Activities | |||||
| Net income | $ | 2,451,652 | $ | 670,143 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||
| Shares issued for services | - | 75,040 | |||
| Depreciation, depletion and amortization | 1,011,602 | 360,282 | |||
| Gain from change in fair value of put option | (68,251) | (47,699) | |||
| Cumulative effect of change in accounting principle | - | 11,813 | |||
| Loss on sale of equipment | 5,586 | - | |||
| Amortization of deferred compensation | 204,525 | 221,198 | |||
| Accretion of discounted asset retirement liability and note payable | 83,730 | 32,212 | |||
| Changes in assets and liabilities: | |||||
| Accounts receivable | (656,864) | (119,474) | |||
| Prepaid expenses | (4,201) | (27,807) | |||
| Accounts payable and accrued liabilities | 1,570,831 | 74,787 | |||
| Deferred income taxes | 1,397,074 | 402,455 | |||
| Net Cash Provided by Operating Activities | 5,995,684 | 1,652,950 | |||
| Cash Flows from Investing Activities | |||||
| Proceeds from sale of equipment | 10,500 | - | |||
| Cash payments on purchase of East Hobbs property | (1,028,000) | - | |||
| Cash payments on purchase of Furhman-Mascho property | (711,802) | - | |||
| Purchase and development of oil and gas properties | (4,802,141) | (3,050,558) | |||
| Purchase of property, plant & equipment | - | (26,686) | |||
| Maturity of long-term investment | 25,234 | 51,268 | |||
| Purchase of office equipment | (41,423) | (4,306) | |||
| Net Cash Used in Investing Activities | (6,547,632) | (3,030,282) | |||
| Cash Flows From Financing Activities | |||||
| Proceeds from issuance of common stock and warrants, net of offering costs | 8,383,557 | 1,580,328 | |||
| Proceeds from exercise of warrants | 354,124 | 33,950 | |||
| Issuance of note payable | 2,000,000 | - | |||
| Payment of notes payable | (10,008,440) | - | |||
| Collection of common stock subscription receivable | - | 157,500 | |||
| Payment of accrued dividends to preferred stockholders | - | (114,685) | |||
| Net Cash Provided by Financing Activities | 729,241 | 1,657,093 | |||
| Net Increase in Cash | 177,293 | 279,761 | |||
| Cash at Beginning of Year | 1,076,676 | 796,915 | |||
| Cash at End of Year | $ | 1,253,969 | $ | 1,076,676 | |
The accompanying notes are an integral part of these financial statements.
ARENA RESOURCES, INC.
STATEMENTS OF CASH FLOWS (CONTINUED)
(As Restated - Note 2)
| For the Years Ended December 31 | 2004 | 2003 | |||
| Supplemental Cash Flow Information | |||||
| Cash paid for interest | $ | 158,950 | $ | 38,798 | |
| Non-Cash Investing and Financing Activities | |||||
| Common stock issued for properties | $ | 34,500 | $ | 319,550 | |
| Asset retirement obligation incurred in property acquisition | - | 338,271 | |||
| East Hobbs property was acquired as follows: | |||||
| Fair value of assets acquired | $ | 10,354,964 | |||
| Liabilities assumed | (78,654) | ||||
| Notes payable incurred | (9,008,440) | ||||
| Common stock issued | (239,870) | ||||
| Cash paid | $ | 1,028,000 | |||
| Fuhrman-Mascho property was acquired as follows: | |||||
| Fair value of assets acquired | $ | 11,479,742 | |||
| Liabilities assumed | (513,247) | ||||
| Note payable incurred, net of $30,000 unamortized discount | (8,970,000) | ||||
| Put options issued | (160,379) | ||||
| Common stock issued | (1,260,091) | ||||
| Call options received | 135,777 | ||||
| Cash paid | $ | 711,802 | |||
The accompanying notes are an integral part of these financial statements.
Organization and Nature of Operations – Arena Resources, Inc. (the “Company”) is a Nevada corporation that owns interests in oil and gas properties located in Oklahoma, Texas, Kansas and New Mexico. The Company is engaged primarily in the acquisition, exploration and development of oil and gas properties and the production and sale of oil and gas.
Use of Estimates – The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Cash – The Company had deposits with a bank that are $1,153,969 in excess of federally insured limits at December 31, 2004.
Oil and Gas Properties – The Company uses the full cost method of accounting for oil and gas properties. Under this method, all costs associated with acquisition, exploration, and development of oil and gas properties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. Capitalized costs are categorized either as being subject to amortization or not subject to amortization.
All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent engineers. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Depletion and amortization expense for the year ended December 31, 2004, was $997,694, based on depletion at the rate of $4.47 per barrel-of-oil-equivalent and for the year ended December 31, 2003, was $360,282, based on depletion at the rate of $2.79 per barrel-of-oil-equivalent.
In addition, capitalized costs less accumulated amortization and related deferred income taxes shall not exceed an amount (the full cost ceiling) equal to the sum of: the present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; plus the cost of properties not being amortized; plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized; less income tax effects related to differences between the book and tax basis of the properties.
Support and Office Equipment – Depreciation of support and office equipment is computed using the straight-line method over the estimated useful lifes of the assets which are currently five to seven years. Depreciation expense was $13,908 and $9,950 for the years ended December 31, 2004 and 2003, respectively.
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.
Earnings Per Share – Basic earnings per share is computed by dividing net income by the weighted-average number of common shares outstanding during the year. Diluted earnings per share is calculated to give effect to potentially issuable dilutive common shares.
Major Customers – During the year ended December 31, 2004, sales to two customers represented 43% and 31% of total sales, respectively. At December 31, 2004, these two customers made up 43% and 22% of accounts receivable, respectively. During the year ended December 31, 2003, sales to three customers represented 51%, 19% and 11% of total sales, respectively. At December 31, 2003, these three customers made up 46%, 16% and 17% of accounts receivable, respectively.
Stock-Based Employee Compensation – 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 8. The Company applies the recognition and measurement principles of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB 25) and related interpretations in accounting for its stock-based compensation awards to employees. The Company recognized compensation expense relating to those stock options of $204,525 and $221,198 for the years ended December 31, 2004 and 2003, respectively.
Alternately, Statement of Financial Accounting Standards (SFAS) No. 123, Accounting for Stock-Based Compensation (SFAS No. 123), allows companies to recognize compensation expense over the related service period based on the grant date fair value of the stock option awards. The following table illustrates the effect on net income and basic and diluted earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation:
| For the Years Ended December 31, | 2004 | 2003 | |||
| Net income, as reported | $ | 2,451,652 | $ | 670,143 | |
| Add: Stock based employee compensation included in net income, net | |||||
| of related tax effects | 128,365 | 139,355 | |||
| Deduct: Total stock-based employee compensation expense determined under the | |||||
| fair value based method for all awards, net of related tax effects | (345,068) | (372,935) | |||
| Pro Forma Net Income | $ | 2,234,949 | $ | 436,563 | |
| Income Per Common Share | |||||
| Basic, as reported | $ | 0.31 | $ | 0.10 | |
| Basic, pro forma | 0.28 | 0.06 | |||
| Diluted, as reported | 0.28 | 0.09 | |||
| Diluted, pro forma | 0.26 | 0.06 | |||
The pro forma estimated after-tax stock-based compensation expense under SFAS 123 for the years ending December 31, 2005, 2006 and 2007 relating to options outstanding at December 31, 2004, will be approximately $128,000, $75,000 and $37,000, respectively. These amounts will change as the result of stock options granted on January 1, 2005 and will be recognized in the results of operations beginning July 1, 2005 upon adoption of Statement 123(R), as discussed below.
Stock-Based Compensation to Non-Employees – The Company accounts for its stock-based compensation issued to non-employees using the fair value method in accordance with SFAS No. 123, “Accounting for Stock-Based Compensation.” Under SFAS No. 123, stock-based compensation is determined as either the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable. The measurement date for these issuances is the earlier of the date at which a commitment for performance by the recipient to earn the equity instruments is reached or the date at which the recipient’s performance is complete.
Cumulative Effect of Change in Accounting Principle – The Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003. In accordance with the transition provisions of SFAS No. 143, on that date the Company recorded asset retirement costs and liabilities and recorded an adjustment for the cumulative effect on prior years of adopting SFAS No. 143 in the amount of $11,813 as a reduction in earnings, which had no effect on basic or diluted earnings per share.
Recent Accounting Pronouncements – In 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 has issued put options in exchange for oil and gas property interests that have been classified as a liability; therefore, the adoption of the statement did not have an impact on the Company’s financial statements.
In December 2004, the FASB issued Statement No. 123 (Revised 2004), Share-Based Payment (“Statement 123(R)”). Statement 123(R) revises Statement No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. Statement 123(R) requires companies to recognize the cost of employee services received in exchange for stock options and awards of equity instruments based on the grant-date fair value of such options and awards. The Company is required to adopt Statement 123(R) on a prospective basis beginning on July 1, 2005, which will result in the recognition of the remaining unrecognized stock-based compensation computed on a fair value basis over the remaining vesting period. The effect of adopting Statement 123(R) will result in recognition of $87,000 of additional after-tax compensation during the year ending December 31, 2005 from options outstanding at December 31, 2004.
In December 2004, the FASB issued SFAS Statement No. 153, Exchanges of Non-monetary Assets—an amendment of APB Opinion No. 29. This Statement amends APB Opinion 29 to eliminate the exception for non-monetary exchanges of similar productive assets and replaces it with a general exception for exchanges of non-monetary assets that do not have commercial substance. A non-monetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The Statement will be effective in January 2006. The Company does not expect that the adoption of Statement 153 will have a material impact on its financial statements.
During 2003, the Company granted nonqualified stock options to directors and employees to purchase 1,000,000 shares of common stock. The exercise price was 85% of the market value of the Company’s common stock on the dates issued and the options vest over a five-year period. In reliance upon FASB Interpretation No. 44, Accounting for Certain Transactions Involving Stock Compensation, the Company considered the 15% discount from the market price of the Company’s common stock to be reasonable in determining the fair value of the common stock and determined that the time permitted for exercise of the stock options was limited to a reasonable period; therefore, the Company did not recognize any stock-based compensation from the grant of these stock options. However, the Company has recently reevaluated its conclusion with regard to the time permitted for exercise of the stock options and has determined that the five year vesting period is not a reasonable period. As a result, the discount from market value is stock-based compensation. As further discussed in Note 8, the stock-based compensation is being recognized over the five-year vesting period of the options.
In addition, the Company recently determined that it did not recognize 40,000 shares of common stock that were issued as a finder’s fee at their fair value during 2004. The fair value of the common stock has been determined by the market value of the Company’s common stock on the date the shares were issued. The fair value of the finder’s fee was capitalized as part of the acquisition of oil and gas properties subject to amortization.
The Company has restated its 2004 and 2003 financial statements for the effects of these adjustments. As a result of the restatement, the Company recognized additional compensation expense of $204,525 and $221,198 during the years ended December 31, 2004 and 2003, respectively. The cost of oil and gas properties subject to amortization was increased by $35,217 at December 31, 2004 and stockholders’ equity was increased by $193,220 and $81,843 at December 31, 2004 and $2003, respectively. The following tables summarize the effect of the restatement on the 2004 and 2003 financial statements:
| As Previously Reported | Effect of Restatement | As Restated | ||||||
| For the Year Ended December 31, 2004 | ||||||||
| General and administrative expense | $ | 670,325 | $ | 204,525 | $ | 874,850 | ||
| Income before provision for income taxes | 4,053,251 | (204,525) | 3,848,726 | |||||
| Provision for deferred income taxes | 1,473,234 | (76,160) | 1,397,074 | |||||
| Net income | 2,580,017 | (128,365) | 2,451,652 | |||||
| Basic earnings per common share | 0.33 | (0.02) | 0.31 | |||||
| Diluted earnings per common share | 0.30 | (0.02) | 0.28 | |||||
| For the Year Ended December 31, 2003 | ||||||||
| General and administrative expense | $ | 557,576 | $ | 221,198 | $ | 778,774 | ||
| Income before provision for income taxes and cumulative effect of change in accounting principle |
1,305,609 | (221,198) | 1,084,411 | |||||
| Provision for deferred income taxes | 484,298 | (81,843) | 402,455 | |||||
| Income before cumulative effect of change in accounting principle |
821,311 | (139,355) | 681,956 | |||||
| Net income | 809,498 | (139,355) | 670,143 | |||||
| Basic earnings per common share | 0.12 | (0.02) | 0.10 | |||||
| Diluted earnings per common share | 0.11 | (0.02) | 0.09 | |||||
| As Previously Reported | Effect of Restatement | As Restated | ||||||
| As of December 31, 2004 | ||||||||
| Property and equipment, net | $ | 33,843,884 | $ | 35,217 | $ | 33,879,101 | ||
| Total assets | 36,342,307 | 35,217 | 36,377,524 | |||||
| Deferred income taxes | 2,129,993 | (158,003) | 1,971,990 | |||||
| Total long-term liabilities | 13,893,019 | (158,003) | 13,735,016 | |||||
| Additional paid-in capital | 15,223,135 | 35,217 | 15,258,352 | |||||
| Options and warrants outstanding | 2,553,159 | 660,000 | 3,213,159 | |||||
| Deferred compensation | - | (234,277) | (234,277) | |||||
| Retained earnings | 2,823,196 | (267,720) | 2,555,476 | |||||
| Total stockholders' equity | 20,608,623 | 193,220 | 20,801,843 | |||||
| As of December 31, 2003 | ||||||||
| Deferred income taxes | $ | 656,759 | $ | (81,843) | $ | 574,916 | ||
| Total long-term liabilities | 1,663,959 | (81,843) | 1,582,116 | |||||
| Options and warrants outstanding | 813,164 | 660,000 | 1,473,164 | |||||
| Deferred compensation | - | (438,802) | (438,802) | |||||
| Retained earnings | 243,179 | (139,355) | 103,824 | |||||
| Total stockholders' equity | 8,058,430 | 81,843 | 8,140,273 | |||||
| For the Years Ended December 31, | 2004 | 2003 | |||
| Income before cumulative effect of change in accounting principle | $ | 2,451,652 | $ | 681,956 | |
| Cumulative effect of change in accounting principle | - | (11,813) | |||
| Net Income | $ | 2,451,652 | $ | 670,143 | |
| Basic Weighted-Average Common Shares Outstanding | 7,873,213 | 6,759,858 | |||
| Effect of dilutive securities | |||||
| Warrants | 524,173 | 231,476 | |||
| Stock options | 296,792 | 250,342 | |||
| Diluted Weighted-Average Common Shares Outstanding | 8,694,178 | 7,241,676 | |||
| Basic Earnings Per Share | |||||
| Income before cumulative effect of change in accounting principle | $ | 0.31 | $ | 0.10 | |
| Net income | 0.31 | 0.10 | |||
| Diluted Earnings Per Share | |||||
| Income before cumulative effect of change in accounting principle | $ | 0.28 | $ | 0.09 | |
| Net Income | 0.28 | 0.09 | |||
On May 7, 2004, the Company acquired an 82.24% working interest, 67.60% net revenue interest, in the East Hobbs San Andres Property mineral lease (“East Hobbs”) located in Lea County, New Mexico. Although the Purchase and Sales Agreement transferred the revenue and the related operating costs from East Hobbs to Arena beginning March 1, 2004, Arena did not control the property interests until May 7, 2004. As a result, the acquisition date for accounting purposes was May 7, 2004 and the East Hobbs’ operations have been included in the results of operations of Arena from May 7, 2004. Revenues and operating costs for the months of March and April were treated as adjustments to the purchase price.
At the date of acquisition, East Hobbs was comprised of 21 operating oil and gas wells that were unitized into one lease prior to the acquisition. The Company purchased East Hobbs for its current production and cash flow, as well as for the drilling and secondary recovery opportunities from the property. The Company paid $10,008,440 to the sellers, including $9,008,440 paid directly from borrowings under a credit facility and a bridge financing from a bank described more fully in Note 5 . In addition, the Company paid acquisition costs of $28,000 and issued 15,000 shares of common stock valued at $90,000, or $6.00 per share, and 25,000 shares of common stock valued at $149,750, or $5.99 per share, as a finder’s fee on the East Hobbs San Andres Property acquisition. The total acquisition cost was allocated to the assets acquired and the liabilities assumed as follows:
| Accounts receivable | $ | 165,544 | |||
| Oil and gas properties subject to amortization | 10,189,480 | ||||
| Total Assets | 10,355,024 | ||||
| Accounts payable | (21,872) | ||||
| Asset retirement obligation | (56,782) | ||||
| Total Liabilities Assumed | (78,654) | ||||
| Net Assets Acquired | $ | 10,276,370 | |||
On November 18, 2004, Arena Resources, Inc. entered into a binding letter of intent to acquire 100% of the working interest, 75% of the net revenue interest, of the Fuhrman-Mascho Property mineral leases under the terms of Asset Purchase Agreements (the “Agreements”). Under the terms of the Agreements, the sellers transferred effective control of the property to the Company on December 1, 2004 without restrictions. Accordingly, the acquisition date was December 1, 2004. The results of operations of the Fuhrman-Mascho property have been included in the results of operations of the Company from December 1, 2004.
At the date of acquisition, Fuhrman-Mascho property consisted of 84 leases with a total of 174 operating oil and gas wells. The Company purchased Fuhrman-Mascho for its current production and cash flow, as well as for the drilling and development opportunities from the property. On December 20, 2004, the Company made cash payments to the sellers of $9,667,381, issued the sellers 150,013 shares of common stock valued at $1,050,091 or $7.00 per share based on the market value of the common stock over the 2-day period before and after November 18, 2004, issued the sellers put options entitling the sellers to demand that the Company reacquire the 150,013 shares of common stock at $7.00 per share from November 1, 2006 through November 30, 2006, valued at $160,379 using the Black-Scholes option pricing model, and received call options from the sellers entitling the Company to reacquire the 150,013 shares of common stock at $8.50 per share from the date issued through November 1, 2006 and valued at $135,777 using the Black-Scholes option pricing model. In addition, the Company paid acquisition costs of $44,421 and issued 30,000 shares of common stock as a consulting and finder’s fee, valued at $210,000, or $7.00 per share. The consideration paid or issued on December 20, 2004 was discounted to December 1, 2004 at 5% and resulted in recognition of an unamortized discount of $30,000 at December 1, 2004. The acquisition was funded through the use of cash on hand and a credit facility secured from the Company’s principal lender. The acquisition cost was allocated to the assets acquired and the liabilities assumed as follows:
| Oil and gas properties subject to amortization | $ | 11,479,742 | |||
| Asset retirement obligation | (513,247) | ||||
| Net Assets Acquired | $ | 10,966,495 | |||
The following unaudited pro forma information is presented to reflect the operations of the Company as if the acquisitions of the East Hobbs and the Fuhrman-Mascho properties had been completed on January 1, 2004 and 2003, respectively:
| For the Years Ended December 31, | 2004 | 2003 | |||
| (Unaudited) | |||||
| Oil and Gas Revenues | $ | 11,493,181 | $ | 7,885,740 | |
| Income from Operations Before Cumulative Effect of Change in | |||||
| Accounting Principle | 2,833,800 | 1,037,061 | |||
| Net Income | 2,833,800 | 1,025,248 | |||
| Basic Income Per Common Share | |||||
| Income before cumulative effect of change in accounting principle | $ | 0.36 | $ | 0.15 | |
| Net income | 0.36 | 0.15 | |||
| Basic Income Per Common Share | |||||
| Income before cumulative effect of change in accounting principle | $ | 0.33 | $ | 0.14 | |
| Net income | 0.33 | 0.14 | |||
On October 28, 2004, the Company issued 5,000 shares of common stock to an unrelated party as a finder’s fee in connection with the purchase of a 70% interest in the Gibralter well in Mississippi. The shares were valued at $34,500, or $6.90 per share, based on the market value of the common stock on the date issued. Arena paid $214,507 of the costs to drill the exploratory well in exchange for the jointly-operated working interest in the well.
In February 2003 the Company established a $10,000,000 revolving credit facility with an initial borrowing base of $2,000,000. In December 2003, the Company entered into an agreement that increased the facility to $20,000,000, with an increased borrowing base of $4,000,000. On April 14, 2004, the Company changed financial institutions and thereby canceled this credit facility.
On April 14, 2004, the Company established a new $15,000,000 credit facility from a bank with an $8,500,000 initial borrowing base. In November2004, the Company entered into an agreement that increased the facility to $25,000,000, with an increased borrowing base of $15,000,000. Any increases in the borrowing base are subject to written consent by the financial institution. The interest rate is a floating rate equal to the 30, 60 or 90 day LIBOR rate plus 2.25%, currently 5.26% per annum, and is payable monthly. Annual fees for the facility are 1/8 of one percent of the unused portion of the borrowing base. Amounts borrowed under the revolving credit facility are due in April 2007. The revolving credit facility is secured by the Company’s principal mineral interests. In order to obtain the revolving credit facility, loans from two officers were subordinated to the position of the bank. The Company is required under the terms of the credit facility to maintain a tangible net worth of $12,000,000, maintain a 5-to-1 ratio of income before interest, taxes, depreciation, depletion and amortization to interest expense and maintain a current asset to current liability ratio of 1-to-1, not including the $2,000,000 bridge financing arrangement discussed below. On May 7, 2004, the Company drew $8,008,440 under this revolving credit facility to fund the acquisition of the East Hobbs San Andres Property interests. During August 2004, utilizing cash flow from operations and proceeds from the recent secondary offering of common stock and warrants, the Company paid $8,008,440 of principal and related accrued interest due on the credit facility. During December 2004, the Company drew $9,000,000 under this revolving credit facility to fund the acquisition of the Fuhrman Mascho leases and $1,000,000 to help fund development activities. An additional $299,029 is reserved under the revolving credit facility as collateral for standby letters of credit issued to various states.
On April 14, 2004, the Company also entered into to a bridge financing arrangement for $2,000,000 from a bank. On April 21, 2004, the Company borrowed $1,000,000 under the terms of the bridge financing agreement to fund a cash deposit made on the East Hobbs San Andres Property interests. On May 7, 2004, the Company borrowed an additional $1,000,000 under the terms of the bridge financing arrangement to fund the acquisition of the East Hobbs San Andres Property interests. The interest rate on the bridge financing arrangement is a floating rate equal to the 30, 60 or 90 day LIBOR rate plus 2.25%, currently 5.26% per annum, and is payable monthly. This arrangement was established for a one-time purpose to satisfy the funding requirements of the East Hobbs San Andres Property acquisition. The original agreement expired June 30, 2004 and was subsequently extended to July 31, 2004. The bridge financing arrangement was guaranteed by two of the Company’s officers. During August 2004, utilizing cash flow from operations and proceeds from the recent public offering of common stock and warrants, the Company paid $2,000,000 of principal and related accrued interest due under the bridge financing agreement. There are no amounts outstanding on this bridge financing agreement. No new agreements have been established to continue the bridge financing arrangement.
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. The Board of Directors and the officers agreed to extend the notes to January 1, 2006, 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, 2004 and 2003.
The Company granted a put option in connection with the acquisition of oil and gas properties in December 2004. Under the terms of the put option, the seller has the right until December 1, 2006, to require the Company to repurchase the 150,013 common shares at $7.00 per share. The put option is a derivative and as such, the liability has been revalued to its fair value at each balance sheet date with adjustments to fair value being recognized as gain on change in fair value of put options. At December 31, 2004, the fair value of the liability was $160,379, calculated using the Black-Scholes option pricing model with the following assumptions: 3% risk-free interest rate; 33% volatility; 2 years expected life; and 0% dividend yield.
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 adoption of SFAS No. 143 will affect amortization of oil and gas properties on an on-going basis. The increase in oil and gas properties is being amortized as the related oil and gas reserves are produced, and resulted in an increase in depreciation, depletion and amortization for the years ended December 31, 2004 and 2003 of $10,798 and $7,459, respectively. The adoption of SFAS No. 143 also impacted the computation of the ceiling test for the carrying value of oil and gas properties. The ceiling test has changed to include the estimated asset retirement costs in the cost of oil and gas properties and exclude future abandonment costs from the computation of the present value of estimated future net revenues. This change only had a nominal effect on the Company’s ceiling test computation at December 31, 2004 and 2003.
The reconciliation of the asset retirement obligation for the years ended December 31, 2003 and 2004 is as follows:
| Balance, January 1, 2003 | $ | 236,718 | |||
| Liabilities incurred | 338,270 | ||||
| Accretion expense | 32,212 | ||||
| Balance, December 31, 2003 | 607,200 | ||||
| Liabilities incurred | 607,063 | ||||
| Accretion expense | 53,730 | ||||
| Balance, December 31, 2004 | $ | 1,267,993 | |||
The Company is authorized to issue 100,000,000 common shares, with a par value of $0.001 per share, and 10,000,000 Class “A” convertible preferred shares, with a par value of $0.001 per share.
Preferred Stock – There is no preferred stock outstanding.
Common Stock – On August 22, 2002, the Company initiated a $3,000,000 private placement offering of the Company’s common stock at $2.50 per share with a detachable warrant exercisable at $5.00 per share through September 30, 2005. 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. During the year ended December 31, 2003, warrant holders exercised 19,400 warrants with an exercise price of $1.75 for $33,950. Additionally, in 2003 the Company issued 70,947 shares of common stock for services, which the Company valued at an aggregate total of $394,590, or $5.57 per share. The Company capitalized as part of oil and gas properties $319,550 and the remaining $75,040 was charged to expense.
In August 2004, the Company completed a public offering of common stock and warrants as a unit at $6.10 per unit before underwriters’ discount and offering costs. The Company issued 1,667,500 shares of common stock and 1,667,500 warrants to purchase common stock at $7.32 per share, through August 9, 2008. In addition, the Company issued options to the underwriters to purchase 145,000 shares of common stock at $9.00 per share and 145,000 warrants at $0.165 per warrant, which entitles them to purchase 145,000 shares of common stock at $7.32.
During the year ended December 31, 2004, warrant holders exercised 66,800 warrants with an exercise price of $5.00 per share and 11,500 warrants with an exercise price of $1.75 per share for $354,125. Additionally, in 2004 the Company issued 75,000 shares of common stock for services, which the Company valued at an aggregate of $449,053, or $5.99 per share. The Company capitalized as part of oil and gas properties the full $449,053.
Stock purchase warrants issued and exercised during the years ended December 31, 2004 and 2003 are summarized as follows:
| 2004 | 2003 | ||||
| Warrants | Weighted-Average Exercise Price | Warrants | Weighted-Average Exercise Price | ||
| Outstanding at beginning of the year | 1,435,723 | $4.47 | 507,200 | $3.58 | |
| Issued | 1,957,500 | $7.46 | 947,923 | $4.89 | |
| Exercised | (78,300) | $4.52 | (19,400) | $1.75 | |
| Outstanding at End of Year | 3,314,923 | $6.23 | 1,435,723 | $4.47 | |
Stock purchase warrants outstanding at December 31, 2004 are as follows:
| Warrants Outstanding |
Exercise Price | Weighted-Average Remaining Contractual Life |
| 190,300 | $1.75 | 0.5 years |
| 50,000 | 3.00 | 1.7 |
| 1,117,123 | 5.00 | 0.7 |
| 1,667,500 | 7.32 | 3.6 |
| 145,000 | 9.00 | 4.6 |
| 145,000 | 7.49 | 4.6 |
| 3,314,923 | ||
The Company values any shares of stock issued to non-employees at their fair value at the date the recipient has rendered services or otherwise earned the shares.
Call Option – The Company received a call option in December 2004 in connection with the purchase of oil and gas properties. The option permits the Company to repurchase 150,013 shares of its common stock at $8.50 per share through November 1, 2006. The call option is exercisable at the Company’s discretion and was recorded as a reduction of additional paid-in capital based on its fair value of $135,777 on the date received. The fair value of the call option was determined using the Black-Scholes option pricing model with the following assumptions: 3% risk-free interest rate; 34% expected volatility; two year expected life and 0% dividend yield. The call option is part of permanent equity and will not be revalued.
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. The Company recognizes compensation expense related to the 15% discount amount of the exercise price from the market price of the stock at the date of grant over the five year vesting period of the options. The Company recognized compensation expense for the years ended December 31, 2003 and 2004 of $221,198 and $204,525, respectively. A summary of the status of the stock options as of December 31, 2004 and changes during the year then ended is as follows:
| Options | Weighted-Average Exercise Price | ||
| 2003 | |||
| Options granted | 1,050,000 | $3.75 | |
| Options forfeited | (50,000) | 3.70 | |
| Options outstanding December 31, 2003 | 1,000,000 | $3.76 | |
| Options outstanding December 31, 2004 | 1,000,000 | $3.76 | |
| Options exercisable December 31, 2004 | 200,000 | $3.76 | |
The fair value of the options granted during 2003, 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, 2004 was 3.2 years.
In July 2002, the Company borrowed $400,000 from two of its officers under the terms of secured, 10% promissory notes, as more fully described in Note 5 .
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. However, subsequent to December 31, 2004 and effective March 1, 2005, the Company leased an additional 385 square feet of office space at the same location. The Company incurred lease expense of $20,400 for the year ended December 31, 2004. The future minimum lease payments under the operating lease agreement as of December 31, 2004 consist of $24,400 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 $299,029 to allow the Company to do business in those states. The Company intends to renew the standby letters of credit for as long as the Company does business in those states. No amounts have been drawn under the standby letters of credit.
The provision for income taxes consisted of the following:
| For the Years Ended December 31, | 2004 | 2003 | |||
| Current before benefit of operating loss carry forwards | $ | - | $ | 83,686 | |
| Current benefit of operating loss carry forwards | - | (83,686) | |||
| Deferred | 1,397,074 | 402,455 | |||
| Provision for Income Taxes | $ | 1,397,074 | $ | 402,455 | |
The following is a reconciliation of income taxes computed using the U.S. federal statutory rate to the provision for income taxes:
| For the Years Ended December 31, | 2004 | 2003 | |||
| Tax at federal statutory rate (34%) | $ | 1,308,567 | $ | 368,700 | |
| Income not subject to tax | (24,493) | (17,364) | |||
| State tax, net of federal benefit | 127,008 | 51,120 | |||
| Effect of lower effective tax rates | (14,008) | - | |||
| Provision for Income Taxes | $ | 1,397,074 | $ | 402,455 | |
As of December 31, 2004, the Company had net operating loss carry forwards for federal income tax reporting purposes of $73,118 which, if unused, will expire in 2022 and 2024. The net deferred tax liability consisted of the following:
| December 31, | 2004 | 2003 | |||
| Deferred tax liabilities | |||||
| Depreciation | $ | 13,092 | $ | 41,152 | |
| Intangible drilling costs | 2,291,116 | 648,126 | |||
| Asset retirement costs | 380,736 | 208,690 | |||
| Total deferred tax liabilities | 2,684,944 | 897,968 | |||
| Deferred tax assets | |||||
| Depletion and amortization | 95,077 | - | |||
| Asset retirement obligation | 426,628 | 226,486 | |||
| Stock-based compensation | 158,003 | 81,843 | |||
| Operating loss carryforwards | 33,246 | 14,723 | |||
| Total deferred tax assets | 712,954 | 323,052 | |||
| Net Deferred Income Taxes | $ | 1,971,990 | $ | 574,916 | |
Subsequent to December 31, 2004, warrants to acquire 1,061,394 shares of common stock have been exercised. Using the proceeds from the exercise of the warrants, the Company paid $5,000,000 on its outstanding line of credit, reducing the amount outstanding to $5,000,000.
Subsequent to December 31, 2004, the Company sold its interest in the Casey lease to an unrelated party for a nominal amount.
On January 1, 2005, the Company granted nonqualified stock options to directors and employees to purchase 375,000 shares of common stock at $8.30 per share through July 1, 2010. The options The pro forma stock-based employee compensation expense determined under the fair value method for these options, net of related tax effects, for the year ending December 31, 2005 would be $323,126. The effect of adopting FASB Statement No. 123(R) on the stock-based compensation from these stock options will result in recognition of $161,563 of additional after-tax compensation during the year ending December 31, 2005.
Capitalized Costs Relating to Oil and Gas Producing Activities
| December 31, | 2004 | 2003 | |||
| Unproved oil and gas properties | $ | 388,581 | $ | 128,694 | |
| Proved oil and gas properties | 34,068,557 | 8,334,706 | |||
| Drilling advances on uncompleted projects | 900,000 | 351,000 | |||
| Support and office equipment | 87,087 | 67,458 | |||
| Total capitalized costs | 35,444,225 | 8,881,858 | |||
| Less accumulated depreciation and amortization | (1,565,124) | (559,229) | |||
| Net Capitalized Costs | $ | 33,879,101 | $ | 8,322,629 | |
Costs Incurred in Oil and Gas Producing Activities
| For the Years Ended December 31, | 2004 | 2003 | |||
| Acquisition of proved properties | 21,706,166 | 2,692,039 | |||
| Acquisition of unproved properties | 43,082 | 147,000 | |||
| Exploration costs | 216,805 | 326,410 | |||
| Development costs | 4,027,754 | 849,864 | |||
| Total Costs Incurred | $ | 25,993,807 | $ | 4,015,313 | |
Results of Operations from Oil and Gas Producing Activities – The Company’s results of operations from oil and gas producing activities exclude interest expense, accretion expense, gain from change in fair value of put options and the cumulative effect of change in accounting principle. Income taxes are based on statutory tax rates, reflecting allowable deductions.
| For the Years Ended December 31, | 2004 | 2003 | |||
| Oil and gas revenues | $ | 8,482,130 | $ | 3,665,477 | |
| Production costs | (1,975,835) | (1,149,136) | |||
| Production taxes | (629,703) | (269,563) | |||
| Depreciation and amortization | (1,011,602) | (360,282) | |||
| Operating expenses of oil and gas producing activities | (313,953) | (221,498) | |||
| Results of operations before income taxes | 4,551,037 | 1,664,998 | |||
| Provision for income taxes | (1,683,884) | (616,049) | |||
| Results of Oil and Gas Producing Operations | $ | 2,867,153 | $ | 1,048,949 | |
Reserve Quantities Information – The following estimates of proved and proved developed reserve quantities and related standardized measure of discounted net cash flow are estimates only, and do not purport to reflect realizable values or fair market values of the Company’s reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. All of the Company’s reserves are located in the United States of America.
Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and methods.
The standardized measure of discounted future net cash flows is computed by applying year-end prices of oil and gas to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows.
| For the Years Ended December 31, | 2004 | 2003 | |||
| Oil (1) | Gas (1) | Oil (1) | Gas (1) | ||
| Proved Developed and Undeveloped Reserves | |||||
| Beginning of year | 7,050,167 | 3,408,754 | 4,113,936 | 3,187,757 | |
| Purchases of minerals in place | 8,764,087 | 6,431,437 | 3,175,357 | 570,924 | |
| Improved recovery and development | - | 640,000 | 18,066 | 229,626 | |
| Production | (195,167) | (169,002) | (117,646) | (67,329) | |
| Revision of previous estimate | 3,931,577 | (311,648) | (139,546) | (512,224) | |
| End of year | 19,550,664 | 9,999,541 | 7,050,167 | 3,408,754 | |
| Proved Developed at end of year | 4,721,293 | 4,615,265 | 1,580,531 | 1,612,738 | |
1 Oil reserves are stated in barrels; gas reserves are stated in thousand cubic feet.
Standard Measure of Discounted Cash Flows
| December 31, | 2004 | 2003 | |||
| Future cash flows | $ | 814,346,791 | $ | 218,026,254 | |
| Future production costs | (171,518,828) | (64,157,199) | |||
| Future development costs | (61,975,106) | (13,609,384) | |||
| Future income taxes | (187,392,403) | (45,778,941) | |||
| Future net cash flows | 393,460,454 | 94,480,730 | |||
| 10% annual discount for estimated timing of cash flows | (188,219,704) | (49,474,633) | |||
| Standardized Measure of Discounted Cash Flows | $ | 205,240,750 | $ | 45,006,097 | |
| For the Years Ended December 31, | 2004 | 2003 | |||
| Beginning of the year | $ | 45,006,097 | $ | 27,997,824 | |
| Purchase of minerals in place | 142,824,938 | 21,333,720 | |||
| Extensions, discoveries and improved recovery, less related costs | 347,652 | 691,469 | |||
| Development costs incurred during the year | 5,387,638 | 320,102 | |||
| Sales of oil and gas produced, net of production costs | (5,876,333) | (2,302,405) | |||
| Accretion of discount | 4,882,064 | 3,012,793 | |||
| Net changes in price and production costs | 74,777,221 | 8,222,075 | |||
| Net change in estimated future development costs | (3,187,159) | 39,219 | |||
| Revision of previous quantity estimates | 42,149,044 | (53,098) | |||
| Revision of estimated timing of cash flows | (27,509,967) | (5,468,732) | |||
| Net change in income taxes | (73,560,445) | (8,786,870) | |||
| End of the Year | $ | 205,240,750 | $ | 45,006,097 | |