(C)	DESCRIPTION OF FIELDS

The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 2007. “Developed Acreage” refers to acreage on which wells have been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities. “Undeveloped Acreage” refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities whether or not the acreage contains proved reserves.

		2007			12/31/2007			Average
		Production			Proved			Working			Developed Acreage						Undeveloped Acreage						Total Acreage
		BOE			Reserves-BOE			Interest			Gross			Net			Gross			Net			Gross			Net
Marion–LA			36,627			298,025			100.00	%		10,300			10,300			11,200			11,200			21,500			21,500
Days Creek–AR			7,246			551,959			85.00	%		480			408			260			221			740			629
Delhi–LA			5,203			1,976,170			95.77	%		520			498			880			843			1,400			1,341
Hospah–NM			—			—			100.00	%		—			—			2,080			2,080			2,080			2,080
Belton– KY			803			5,580			100.00	%		110			110			9,215			9,215			9,325			9,325
South Belridge–CA			22,261			60,814			50.00	%		45			23			1,830			915			1,875			938
Stephens (Deep)–AR			705			38,170			24.00	%		80			19			1,034			248			1,114			267
Stephens (Jones)–AR			—			24,890			75.00	%		—			—			40			30			40			30
Total			72,845			2,955,608						11,535			11,358			26,539			24,752			38,074			36,110

 

An element of an oil or natural gas lease is the obligation to drill upon the fields that are acquired. If the Company is not successful in securing its 2008 funding for a drilling and development budget of approximately $12.4 million, some of leases might be lost. So as to maintain its leases in the Stephens Field, six wells must be drilled by the end of 2008 or the Company will lose its rights to the undeveloped acres. The Company has already drilled four of these wells. The South Belridge Field lease carries a 10 well per year drilling commitment or the remaining undeveloped acres could be lost, but the Company’s working interest partner and the operator has been complying with this commitment even without the Company’s contribution. In that scenario, the Company only forfeits the well spacing acres of any wells in which it chooses to go non-consent. The Marion Field, Days Creek Field, and Delhi Field do not have any future drilling commitments and current production is sufficient to maintain those leases. The Company is the mineral interest owner in its initial 3,008 acres of the Belton Field and therefore there is no drilling or production requirements on this property. During 2007, the Company has leased an additional 6,317 surrounding acres, typically under five year leases with an option to renew the lease for an additional five years for a rental fee.

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A description of the Company’s producing oil and natural gas properties is as follows:

Marion Field (Monroe Gas Field), Louisiana

The Company purchased this approximately 21,500 acre natural gas field in December 2005 which included a pipeline and operational equipment.

	·	Wells: 476 currently producing though existing pipeline needs modernization and enhancement
	·	The Company currently has a 100% working interest (“WI”) and an average net revenue interest (“NRI”) of 76%
	·	Natural gas production from the Arkadelphia zone
	·	Strategic plan initiated for natural gas field workover program to increase production revenue, and pipeline replacement/repair program to handle increased production of natural gas
	·	Developing strategic plan for exploration and development of deeper prospective pay zones

Days Creek Field, Arkansas

In November 2006, the Company purchased approximately 740 acres in Miller County Arkansas using $400,000 in cash and three convertible notes in an aggregate principal amount of $6.0 million, which notes are convertible into an aggregate of 8,000,000 shares of common stock.

	·	Wells: 13 existing wells with ten planned workovers
	·	The Company currently has a 85% WI and a 57.25% NRI
	·	There are four actively operating oil and natural gas wells in the Smackover Zone
	·	Developing strategic plan for additional in-field drilling and development

Delhi Field, Louisiana

The Company purchased an approximately 1,400 acre lease in December 2006 that is a water injection oil field.

	·	Proved oil reserves in the Mengel Sands
	·	Wells: 12 productive wells are in place and completed
	·	The Company currently has a 95.77% WI and a 82.67% NRI
	·	Active well workover program on existing oil wells
	·	Developing strategic plan for implementation of waterflood program

Hospah, Lone Pine & Clovis Oil and Natural Gas Fields, New Mexico

Over the course of two years, the Company has negotiated and continues to negotiate the purchase of acreage in New Mexico. We currently have acquired leases to 2,080 acres in Hospah while working towards leasing more acreage near Clovis, New Mexico in McKinley County.

	·	The Company has a 100% WI and an 73.3% NRI on its first 2,080 acres in Hospah
	·	Oil and natural gas production since 1927 from the Hospah Sandstones reservoir located on the field have yielded nearly 22 million barrels of oil and nearly 53 bcf of gas through 2005

  Belton Field, Kentucky

The Belton Field was the Company’s first acquisition in April of 2004, acquiring 3,008 acres initially and since that time the Company has leased an additional 6,317 surrounding acreage, all located in Muhlenberg County, Kentucky.

	·	Wells: three oil wells and three natural gas wells are newly drilled and in various stages of completion with one additional well not yet drilled
	·	The Company currently has a 100% WI and an approximate 79.6% NRI
	·	A drilling program is nearly completed to develop shallow reserves and explore for deeper productive oil and natural gas pay zones

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South Belridge Field, California

The Company negotiated a joint operating agreement (“JOA”) with Orchard Petroleum, Inc. in February 2005 on a prospect of approximately 960 acres in Kern County, California. The Company spent a total of $1.72 million for the opportunity to buy into this project with Orchard for a 75% working interest of Orchard’s 75% interest. In addition, the Company was obligated to pay for the first $28.5 million in capital expenditures (CAPEX) to drill wells, later reduced to $23.5 million for a 50% working interest. In support of Orchard’s drilling operations, the Company invested the $23.5 million on wells drilled in the South Belridge field for a total investment of $25.2 million including the initial $1.72 million buy in. In early 2007, the Company paid $500,000 for a 50% working interest in 600 acres of section 18 which is adjacent to the original 960 acre prospect. The Company sold this property in April 2008 to reduce outstanding debt.

Stephens Field, Arkansas

The Company purchased rights to approximately 1,114 acres in Columbia County, Arkansas in December 2006. The Company also bought into the single well in Lafayette County, Arkansas, the Jones #1 well, in 2007.

	·	Wells: five wells drilled and two of those wells are completed
	·	The Company currently has a 24% WI and a 16.5% NRI at depths of 2,500 feet and deeper
	·	The Company currently has a 75% WI and a 45.75% NRI in the Jones #1 well

(D)  OIL AND NATURAL GAS OPERATIONS, PRODUCTION AND DEVELOPMENT

Volumes, Prices and Oil & Natural Gas Operating Expense

The following table sets forth certain information regarding the production volumes of, average sales prices received for and average production costs associated with our sales of oil and natural gas for the periods indicated.

		Year Ended December 31,
		2007			2006
Production volumes:
Oil (Bbls)			23,880			16,167
Natural gas (Mcf)			293,788			313,585
Barrel of oil equivalent (BOE)			72,845			68,431
Average sales prices:
Oil (per Bbl)		$	71.77		$	62.57
Natural gas (per Mcf)		$	6.20		$	6.27
Barrel of oil equivalent (per BOE)		$	48.54		$	43.54
Average costs (per BOE)    (1)		$	43.36		$	30.91

 

(1)	Includes direct lifting costs (labor, repairs and maintenance, materials and supplies), workover costs and the administrative costs of production offices, insurance and property and severance taxes.

Oil and Natural Gas Reserves

The reserves as of December 31, 2007 were derived from reserve estimates prepared by the independent reserve engineers; Aluko & Associates, Inc. for the Delhi Field and the South Belridge Field, Haas Petroleum Engineering Services, Inc. for the Belton Field and the Stephens Field, Netherland, Sewell & Associates, Inc. for the Marion Field, and Lee Keeling and Associates, Inc. for the Days Creek Field. No reserve reports were provided to any government agency. The PV-10 value was derived using constant prices as of the calculation date, discounted at 10% per annum on a pretax basis, and is not intended to represent the current market value of the estimated oil and natural gas reserves owned by the Company. For further information concerning the present value of future net revenues from these proved reserves, see Note 14 of notes to Consolidated Financial Statements.

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The following table sets forth our estimated net proved oil and natural gas reserves and the PV-10 value of such reserves as of December 31, 2007.

		Proved Reserves
		Developed			Undeveloped			Total
Oil and condensate (Bbls)			143,806			2,480,489			2,624,295
Natural gas (Mcf)			1,987,875			—			1,987,875
Total proved reserves (BOE)			475,119			2,480,489			2,955,608
PV-10 Value (1)(2)		$	4,845,085		$	100,019,176		$	104,864,261

(1)	The PV-10 value as of December 31, 2007 is pre-tax and was determined by using the December 31, 2007 sales prices, which averaged $92.79 per Bbl of oil, $6.46 per Mcf of natural gas. Management believes that the presentation of PV-10 value may be considered a non-GAAP financial measure. Therefore we have included a reconciliation of the measure to the most directly comparable GAAP financial measure (standardized measure of discounted future net cash flows in footnote (2) below). Management believes that the presentation of PV-10 value provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because many factors that are unique to each individual Company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies.
	Management also uses this pre-tax measure when assessing the potential return on investment related to its oil and natural gas properties and in evaluating acquisition candidates. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of the estimated oil and natural gas reserves owned by us. The PV-10 value should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
(2)	Future income taxes and present value discounted (10%) future income taxes were $29,301,076 and $16,026,188, respectively. Accordingly, the after-tax PV-10 value of Total Proved Reserves (or “Standardized Measure of Discounted Future Net Cash Flows”) is $88,838,073.

Development, Exploration and Acquisition Capital Expenditures

The following table sets forth certain information regarding the gross costs incurred in the purchase of proved and unproved properties and in development and exploration activities.

 

		Year Ended December 31,
		2007			2006
Property acquisition costs:
Unproved		$	778,312		$	6,094,136
Proved			4,726,215			5,929,225
Exploration costs			3,227,137			85,453
Development costs			3,704,171			7,446,629
Asset retirement obligation (1)			330,299			890,355
Total costs incurred		$	12,766,134		$	20,445,798

 

(1)	Includes non-cash asset retirement obligations accrued in accordance with SFAS No. 143 of $330,299 and $890,355, respectively, for the years ended December 31, 2007 and 2006, respectively.

Productive Wells

Productive wells are producing wells or wells capable of production. This does not include water source wells, water injection wells or water disposal wells. Productive wells do not include any wells in the process of being drilled and completed that are not yet capable of production, but does include old productive wells that are currently shut-in, because they are still capable of production. The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of December 31, 2007.

		Company
		Operated						Other						Total
		Gross			Net			Gross			Net			Gross			Net
Oil			38			34.1			9			6.8			47			40.9
Natural gas			515			515.0			—			—			515			515.0
Total			553			549.1			9			6.8			562			555.9

 

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Drilling Activity

The number of wells drilled refers to the number of wells (holes) completed at any time during the fiscal years, regardless when drilling was initiated. The term “completion” refers to the   installation of permanent equipment for the production of oil or natural gas, or, in the case of a dry hole, to the reporting of abandonment to the appropriate agency. The following table sets forth our drilling activity for the last two years ended December 31, 2007 and 2006. The Company had several wells drilled but not yet completed at December 31, 2007 that are excluded from the following table. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest therein.

		Year Ended December 31,
		2007						2006
		Gross			Net			Gross			Net
Exploratory Wells
Productive			4			2.5			—			—
Nonproductive			—			—			—			—
Total			4			2.5			—			—
Development Wells
Productive			—			—			1			1
Nonproductive			—			—			—			—
Total			—			—			1			1

Delivery Commitments

We are not obligated to provide a fixed and determinable quantity of oil or natural gas in the near future under existing contracts or agreements. Furthermore, during the last three years we had no significant delivery commitments.

(E)	ENHANCED OIL RECOVERY

A focus of the Company involves enhanced oil recovery (“EOR”). This refers to the recovery of oil that is left behind after primary recovery methods are either exhausted or no longer economical. The Company can utilize both conventional and non conventional methods to achieve EOR.

Primary production is the first oil out, the “easy” oil. Once a well has been drilled and completed in a hydrocarbon-bearing zone, the natural pressures at that depth may and often do cause the oil to flow through the rock or sand formation toward the lower pressure wellbore.

Secondary recovery methods are used when there is insufficient underground pressure to move the remaining oil. Water-flooding is one of the most common and efficient secondary recovery processes. Water is injected into the oil reservoir in certain wells in order to renew a part of the original reservoir energy. As this water is forced into the oil reservoir, it spreads out from the injection wells and pushes some of the remaining oil toward the producing wells. Eventually the water front will reach these producers and increasingly larger quantities of water will be produced with a corresponding decrease in the amount of oil. Other processes include stimulations by re-permeating through technologies for fracturing formations “fracing”, as well as lateral horizontal drilling. Management believes that in time and with prolonged deployment in a number of its wells, the lateral drilling technology available to Maxim will prove most efficient at the lowest cost. Tertiary recovery involves injecting other gases, such as carbon dioxide, to stimulate the flow of the oil and to produce remaining fluids.

EOR Technology Available to the Company

Lateral Horizontal Drilling (Water Jetting)

Utilizing existing drilled wells, the Lateral Horizontal Drilling Technology (“LHD Technology”) is a technique where the well bore casing is milled at different directions and at different levels in a “wheel and spoke” fashion and then fluid is jetted at high pressure through the formation. The jetted fluid can penetrate laterally for up to 300 feet in up to four directions at any given depth. LHD Technology can be conducted at a fraction of the time and cost of conventional drilling methods. The LHD Technology employs low volumes of water, is friendly to the environment, and no attendant mud pits or drilling fluids are required. The LHD Technology can be adapted for use on both new and existing wells, although the Company believes that it is most effective on formations with low production.

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LHD Technology can provide the Company an alternative, non-traditional, method to recover oil and natural gas reserves that otherwise may have been beyond the reach of conventional technologies.   LHD Technology can also be utilized for fracturing, water injection and acidizing intervals or water zones at a fraction of the time and cost of conventional methods.

Propellant Fracturing

 

In 2006, the Company began utilizing a fracturing technology that employs a propellant fracturing tool using solid propellant, referred to as “low order explosives” to generate high pressure gas at a rapid rate which can be tailored to formation characteristics. The technique is designed to create multiple fractures radiating more than 20 feet from the wellbore and avoids pulverizing and compacting the rock.

 

This propellant fracturing tool is compatible with both open and cased-hole completions.  The tool is usually deployed by wireline or coiled tubing. Typically little or no cleanup is required, and the well can usually be put back on production soon after the stimulation, hence offering little “down” time.

(F)  ORGANIZATION

 

The company has set in place a corporate structure that organizes different functions and individual holdings in separate subsidiaries. In this way it can finitely address both budget and funding/reporting needs, while also limiting any unnecessary corporate exposure.

 

1) Maxim TEP Financial, LLC coordinates all Company funding and finance, as well as coordination and presentation of the Company to public markets

 

2) MTEP Land & Mineral Management, LLC oversees drilling and field enhancement operations within each of the Company’s wholly owned subsidiaries:

 

	A.	Axiom TEP, LLC and Delhi Oil & Gas, LLC controlling the two Louisiana properties
	B.	Smackover Creek Energy, LLC and DC Operating Co., LLC for two Arkansas properties
	C.	HM Operating Company, LLC and MTEP Clovis (being formed) for two New Mexico acquisitions
	D.	Mud River Energy, LLC controlling the Company’s Kentucky operations
	E.	Tiger Bend Gas Pipeline, LLC controlling the Company’s Louisiana pipeline holdings
	F.	MTEP Technologies, LLC a technology holding firm for the non conventional Radial/Lateral Drilling Licensing, LLC (being formed) owned by the Company
	G.	Tiger Bend Drilling, LLC provides vertical well drilling services

 

The Board of Directors oversees the corporate activities, working in conjunction with the President/CEO and Management team.

 

Employees

 

At May 15, 2008, Maxim and its subsidiaries had a total of 17 full-time employees. There are six employees at the Company’s corporate headquarters in The Woodlands, Texas. See “Item 6, Executive Compensation.”

 

Trademarks and Other Intellectual Property

 

The Company purchased exclusive North American rights for a non-conventional lateral drilling technology invented by Carl Landers, a Director of the Company from inception. The patents comprising this lateral drilling technology are: US Patent Number 5,413,184 Method and Apparatus for Horizontal Well Drilling , issued May 9, 1995; US Patent Number 5,853,056 Method and Apparatus for Horizontal Well Drilling , issued December 12, 1998; and US Patent Number 6,125,949 Method and Apparatus for Horizontal Well Drilling , issued October 3, 2000. There can be no assurance that these patents and the related technology will perform to the Company’ expectations. Further, there can be no assurance that these patents and related technology do not infringe upon the intellectual property rights of others.

 

Distribution Methods

 

Each of our fields that produce oil distributes all of the oil that it produces through one purchaser for each field. We do not have a written agreement with some of these oil purchasers. These oil purchasers pick up oil from our tanks and pay us according to market prices at the time the oil is picked up at our tanks. There is significant demand for oil and there are several companies in our operating areas that purchase oil from small oil producers.

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Each of our fields that produce natural gas distributes all of the natural gas that it produces through one purchaser for each field. We have distribution agreements with these natural gas purchasers that provide us a tap into a distribution line of a natural gas distribution company and to be paid for our natural gas at either a market price at the beginning of the month or market price at the time of delivery, less any transportation cost charged by the natural gas distribution company. These charges can range widely from 2 percent to 20 percent or more of the market value of the natural gas depending on the availability of competition and other factors. Due to the lack of available distribution lines on our South Belridge field, the operator has elected to sell the natural gas produced to a neighboring company to be used on their lease at a high discount.

Competitive Business Conditions

 

We encounter competition from other oil and natural gas companies in all areas of our operations. Because of record high prices for oil and natural gas, there are many companies competing for the leasehold rights to good oil and natural gas prospects. And, because so many companies are again exploring for oil and natural gas, there is often a shortage of equipment available to do drilling and workover projects. Many of our competitors are large, well-established companies that have been engaged in the oil and natural gas business for much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. We may not be able to conduct our operations, evaluate and select properties and consummate transactions successfully in this highly competitive environment.

 

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

 

Source and Availability of Raw Materials

 

We have no significant raw materials. However, we make use of numerous oil field service companies in the drilling and workover of wells. We currently operate in areas where there are numerous oil field service and drilling companies that are available to us.

 

Dependence on One or a Few Customers 

 

There is a ready market for the sale of crude oil and natural gas. Each of our fields currently sells all of its oil production to one purchaser for each field and all of its natural gas production to one purchaser for each field. However, because alternate purchasers of oil and natural gas are readily available at similar prices, we believe that the loss of any of our purchasers would not have a material adverse effect on our financial results.

 

		Year Ended December 31,
		2007			2006
Interconn Resources, Inc. (1)			39	%		51	%
Lion Oil Trading & Transportation, Inc. (1)			17	%		–
Plains Marketing, LP (1)			10	%		–
Orchard Petroleum, Inc. (2)			32	%		47	%

(1)	The Company does not have a formal purchase agreement with this customer, but sells production on a month-to-month basis at spot prices adjusted for field differentials.
(2)	Orchard Petroleum, Inc is the operator of the Company’s wells in California and sells production on the Company’s behalf to Kern Oil & Refining, Co. and Aera Energy, LLC.

Periodic Reports and Available Information

 

We are filing this registration statement under Section 12(g) of the Securities Exchange Act of 1934. The effectiveness of this registration statement subjects us to the periodic reporting requirements imposed by Section 13(a) of the Securities Exchange Act.

 

We will electronically file with the Commission the following periodic reports:

 

·		Annual reports on Form 10-K;
·		Quarterly reports on Form 10-Q;
·		Periodic reports on Form 8-K;
·		Annual proxy statements to be sent to our shareholders with the notices of our annual shareholders' meetings.

 

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In addition to the above reports to be filed with the Commission, we will prepare and send to our shareholders an annual report that will include audited consolidated financial statements.

The public may read and copy any materials we file with the Commission at the Commission's Public Reference Room at 100 F Street NE, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the Commission at 1-800-SEC-0330. Also, the Commission maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that electronically file reports with the Commission.

Government Regulations

 

Our facilities in the United States are subject to federal, state and local environmental laws and regulations. Compliance with these provisions has not had, and we do not expect such compliance to have, any material adverse effect upon our capital expenditures, net earnings or competitive position.

 

Regulation of transportation of oil

 

Sales of crude oil, condensate, natural gas 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, (“FERC”), regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index slightly, effective July 2001. 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 similarly situated 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. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act. The Decontrol Act removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

 

The FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. 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. Beginning in 1992, the FERC issued Order No. 636 and a series of related orders to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. 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.

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In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect.

 

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states on shore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase our costs of getting gas to point of sale locations.

 

Intrastate natural gas transportation is also 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. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

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. Such regulations govern conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

 

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

Environmental, health and safety regulation

 

Our operations are subject to stringent and complex federal, state, local and provincial laws and regulations governing environmental protection, health and safety, including the discharge of materials into the environment. These laws and regulations may, among other things:

	§	Require the acquisition of various permits before drilling commences;
	§	Restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;
	§	Limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
	§	Requires remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

 

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs.

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The following is a summary of the material existing environmental, health and safety laws and regulations to which our business operations are subject.

 

Waste handling . The Resource Conservation and Recovery Act, or “RCRA”, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or “EPA”, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

 

Comprehensive Environmental Response, Compensation and Liability Act . The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA”, also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, in connection with the release of a hazardous substance into the environment. Persons potentially liable under CERCLA include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance to the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources and the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

 

We own and lease, and may in the future operate, numerous properties that have been used for oil and natural gas exploitation and production for many years. Hazardous substances may have been released on, at or under the properties owned, leased or operated by us, or on, at or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been or are operated by third parties or by previous owners or operators whose handling, treatment and disposal of hazardous substances were not under our control. These properties and the substances disposed or released on, at or under them may be subject to CERCLA, RCRA and analogous state laws. In certain circumstances, we could be responsible for the removal of previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination. In addition, federal and state trustees can also seek substantial compensation for damages to natural resources resulting from spills or releases.

 

Water discharges . The Federal Water Pollution Control Act, or the “Clean Water Act”, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil and other substances generated by our operations, into waters of the United States or state waters. Under these laws, the discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

 

The Safe Drinking Water Act, or “SDWA”, and analogous state laws impose requirements relating to underground injection activities. Under these laws, the EPA and state environmental agencies have adopted regulations relating to permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as prohibitions against the migration of injected fluids into underground sources of drinking water.

 

Air emissions . The Federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, EPA and certain states have developed and continue to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and analogous state laws and regulations.

The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has not acted upon recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and natural gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations.

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National Environmental Policy Act . Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All exploration and production activities on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects on federal lands.

 

Health safety and disclosure regulation . We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and similar state statutes require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations.

 

We expect to incur capital and other expenditures related to environmental compliance. Although we believe that our compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, we cannot assure you that the passage of more stringent laws or regulations in the future will not have a negative impact on our financial position or results of operation.

ITEM 2.  FINANCIAL INFORMATION

 

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this Registration Statement. Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations.

 

Going concern

 

As presented in the accompanying consolidated financial statements, the Company has incurred net losses of $29,985,540 and $36,822,509 during the years ended December 31, 2007 and 2006, respectively, and losses are expected to continue in the near term. Current liabilities exceeded current assets by $59,195,129 and $36,808,692 at December 31, 2007 and 2006, respectively, and the accumulated deficit is $89,244,111 and $59,258,571 at December 31, 2007 and 2006, respectively. Amounts outstanding and payable to creditors are in arrears and the Company is in negotiations with certain creditors to obtain extensions and settlements of outstanding amounts. The Company is currently in default on certain of its debt obligations and the Company has no future borrowings or funding sources available under existing financing arrangements. Management anticipates that significant additional capital expenditures will be necessary to develop the Company’s oil and natural gas properties, which consist primarily of proved reserves that are non-producing, before significant positive operating cash flows will be achieved.

 

Management's plans to alleviate these conditions include the renegotiation of certain trade payables, settlements of debt amounts with stock, deferral of certain scheduled payments, and sales of certain non-core properties, as considered necessary. In addition, management is pursuing business partnering arrangements for the acquisition and development of its properties as well as debt and equity funding through private placements. Without outside investment from the sale of equity securities, debt financing or partnering with other oil and natural gas companies, operating activities and overhead expenses will be reduced to a pace that available operating cash flows will support.

The accompanying consolidated financial statements are prepared as if the Company will continue as a going concern. The financial statements do not contain adjustments, including adjustments to recorded assets and liabilities, which might be necessary if the Company were unable to continue as a going concern.

 

General Overview

 

We are an independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties. Our areas of operation include California, Louisiana, Arkansas and Kentucky.

 

Over our first three years, we have emphasized the acquisition of properties that provided current production and upside potential through further development and the enhanced recovery through secondary/tertiary technology innovations. Our drilling and EOR activity is directed at infield development; specifically on projects that we believe provide repeatable successes in particular fields. Our combination of acquisitions and development allows us to direct our capital resources to what we believe to be the most advantageous investments that result in immediate cash-flow, reduced risk by using developmental drilling, and reserve value.

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We target the purchase of operated and non-operated properties that should meet or exceed our rate of return criteria. For acquisitions of properties with additional development, exploitation and exploration potential, our focus has been on acquiring operated properties so that we can better control the timing and implementation of capital spending. We may sell properties when we believe that the sale price realized will provide an above average rate of return for the property or when the property no longer matches the profile of properties we desire to own.

 

Using that business model, we constantly look for drilling opportunities for new proved reserves and to develop proved undeveloped reserves on properties that provide low-risk, immediate revenue. In future years, the Company will strive to create a balance of near-term and long-term production, but for now our focus is on current and near-term production. We target the acquisition of properties with proved reserves that we can quickly develop and subsequently produce to help us meet our production goals.

 

At the inception of the Company, management understood that during the first years of the Phase One-Acquisitions Phase, the Company would report losses and increased expenses as a result of the overhead, financing costs, and initial drilling and the lack of oil and natural gas sales, or the limited sales in the case of the acquisition of fields that had some oil and natural gas production.

 

During 2006 and 2007, Maxim initiated its Phase Two, drilling program. This drilling program was originally aimed at increasing cash flow from a portion of the existing wells by laterally drilling them to stimulate additional production. From these drilling activities, anticipated production would provide additional cash flow that could be used for ongoing drilling of more wells. This plan includes enhancement and completion work on seven (of the thirteen) wells in Days Creek Field and completion of three remaining wells in Marion Field, as well as the drilling and completion of two wells at the Stephens Field.

 

Oil and Natural Gas Operations—The Company’s principal revenue stream is derived from the sale of oil and natural gas. For the sale of oil, the Company contracts with buyers and distributors who pick up the oil at our tank batteries for a spot price. The majority of the Company’s natural gas production is sold through a marketing company for a spot price. We deliver the gas to an interstate gas pipeline normally at pressures in excess of 600 psi. The quality of the gas stream is rated in British thermal units, (“Btu”) and must be pipeline quality. The spot price is adjusted for changes in Btus.

Drilling Revenues—Because of high prices for oil and natural gas, there are many companies exploring for oil and natural gas resulting in a shortage of equipment available to do drilling and workover projects. Accordingly, the Company formed Tiger Bend Drilling, LLC in early 2006 and purchased two used drilling rigs and then refurbished the rigs and trained crews. The Company’s direct drilling rig investments were intended to be an effective hedge to higher service costs and have a competitive advantage in making acquisitions and in developing the Company’s own leaseholds on a more timely and efficient basis. The Company needed rig availability that could be timed to its free cash flow for capital expenses. Working with a local drilling supervisor, the rigs drilled four new gas wells on our Marion field, followed by one contracted well in mid-2006. The Company decided that the carrying costs of the drilling rigs and equipment outweighed the benefits of ownership and rig availability. Therefore, in November 2006 the Company sold the drilling rigs and related equipment for $1,550,000 and recorded a loss on the sale of approximately $768,000. In 2007, the drilling subsidiary leased a rig and drilled two wells in which the Company had an interest. The drilling subsidiary currently has no activity.

 

Lateral Drilling License Fees, Royalties and Related Services—The Company purchased the master license for the Lander’s Horizontal Drilling Technology (“LHD Technology”), and later completed the acquisition by purchasing the patents from the inventor. The Company initially focused its attention on obtaining aging oil and natural gas properties and enhancing their performance through the use of this wholly-owned proprietary technology. As a new entity, the Company found little internal expertise or resources available to make meaningful improvements to the technology. The Company entered into a series of sublicensing agreements that were intended to fully commercialize the technology and focus on continuing improvements. Through its licensing program, the Company was able to generate needed cash flow from license fees and LHD Technology equipment sales. The Company entered into a contract with another company to jointly market and perform lateral drilling services. The in-house resources required to make the lateral drilling venture a success detracted from the development and operation of the oil and natural gas fields. The Company and its partner terminated the relationship in 2005. The Company wanted to demonstrate its faith in the technology and contracted one of its sub licensees to laterally jet four gas wells in the Marian field. During 2006, the Company determined that it would no longer actively market territorial exclusive licensees for the technology. Sub licensees with exclusive contracts were simply not performing to expected levels and faced no competition when armed with an exclusive license. With the reduction in sub licensing opportunities, the sale of rigs and downhole tools also decreased. In 2007, the Company entered into an agreement with a sub licensee to provide downhole tools, training and technology development for a percent of the gross receipts. Currently, the Company owns one coiled tubing unit designed for LHD Technology in wells less than 2,500 feet deep.

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Revenue Recognition—The Company recognizes oil and natural gas revenues upon transfer of ownership of the product to the customer which occurs when (i) the product is physically received by the customer, (ii) an invoice is generated which evidences an arrangement between the customer and us, (iii) a fixed sales price has been included in such invoice and (iv) collection from such customer is probable. Volumes of oil and natural gas sold are not materially different than volumes produced.

 

The Company recognizes drilling revenues when services are performed and earned.

 

The Company recognizes revenue from issuing sublicenses for the right to use the Company’s LHD Technology and from the sale of specifically constructed lateral drilling rigs and related rig service parts required by the licensees to utilize the LHD Technology. Revenue from license fees is recognized over the term of the license agreement. For license agreements entered into that have an indefinite term, revenue is earned and recorded at closing, subject to the credit worthiness of the licensee if credit terms are extended. License royalty revenue is recognized when licensees drill wells that utilize LHD Technology and a royalty is earned. Revenue generated from the sale of rigs and rig service parts is recognized upon delivery.

 

Commodity pricing risks—The Company’s profitability is highly dependent on the prices of oil and natural gas. Commodity prices are outside of our control and historically have been and are expected to remain volatile. Commodity prices are affected by changes in market demands, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, natural gas liquids and crude oil prices, and therefore, cannot accurately predict revenues. 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.

Operating cost controls—To maintain our competitive position, we must control our lease operating costs and other production costs. As reservoirs are depleted and production rates decline, per unit production costs will generally increase and affect our profitability and operating cash flows. Similar to capital expenditures, our ability to control operating costs can be affected when commodity prices rise significantly. Our production is focused in core areas of our operations where we can achieve economies of scale to assist our management of operating costs.

 

Capital investment discipline—Effectively deploying our very limited resources into capital projects is key to maintaining and growing future production and oil and natural gas reserves. Therefore, maintaining a disciplined approach to investing in capital projects is important to our profitability and financial condition. In addition, our ability to control capital expenditures can be affected by changes in commodity prices. During times of high commodity prices, drilling and related costs often escalate due to the effects of supply versus demand economics. One-hundred percent of our planned 2008 investment in capital projects is dedicated to a foundation of low-risk projects in the United States. By deploying our capital in this manner, we are able to consistently deliver cost-efficient drill-bit growth and provide a strong source of cash flow while balancing short-term and long-term growth targets.

 

Impairment of Oil and Natural Gas Properties— The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment and Disposal of Long-Lived Assets.” Impairment of an individual producing oil and natural gas field is first determined by comparing the undiscounted future net cash flows associated with the proved property to the carry value of the underlying property. If the cost of the underlying property is in excess of the undiscounted future net cash flows the carrying cost of the impaired property is compared to the estimated fair value and the difference is recorded as in impairment loss. Management’s estimate of fair value takes into account many factors such as the present value discount rate, pricing, and when appropriate possible and probable reserves when justified by economic conditions and actual or planned drilling or other development activities. For unevaluated property costs, management reviews these investments for impairment on a property by property basis at each reporting period or if a triggering event should occur that may suggest that an impairment may be required.

 

Accordingly, the Company recorded $7,195,367 and $4,843,688 as impairment of proved oil and natural gas properties and related equipment on the South Belridge Field during the years ended December 31, 2007 and 2006, respectively. Using the prices in effect and estimated proved reserves on December 31, 2006, the write-down would have been approximately $5.3 million, or approximately $0.5 million larger, had we not taken into account subsequent improvements in oil and natural gas prices. Because of the volatility of oil and natural gas prices, no assurance can be given that we will not experience additional write-downs in future periods. The Company recorded $250,000 as impairment of unproved oil and natural gas properties at December 31, 2007 as it was decided to not pursue prospects in the Kansas property thus we allowed those leases to expire. There was no impairment of unproved properties required at December 31, 2006.

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Alternative Investment Market Fund Raising Activities—The Company incurred several pre-initial public offering costs over a one-year period straddling the 2005-2006 fiscal years as the Company investigated and attempted placement on the Alternative Investment Market (“AIM”) of the London Stock Exchange. AIM fund raising activities for 2006 were $2,666,587. AIM fund raising activities in 2006 mostly consisted of $1,271,183 of consulting services, of which $1,162,500 was recorded as the value of 1,550,000 shares of common stock issued for services. Costs of $680,274 in 2006 were incurred for two separate law firms and public accounting firms, one in the United States and one in the United Kingdom. Costs of $368,908 in 2006 were also incurred to secure a third party engineering assessment of the Company’s US based oil and natural gas assets that would not have been required other than for this offering. In addition, these costs include $345,060 in 2006 of incremental increased travel and related expenses in opening and maintaining offices in London. The Company terminated its association with the London based broker for listing on the AIM when it became apparent that funding could not be secured under favorable terms and that tax issues would prove unattractive to all existing shareholders.

Equity, Debt and Asset Based Financing — From inception, the Company has sought investment from accredited investors and through the issuance of debt instruments. The Company has also utilized the offer to investors of net revenue interests (“NRI”), overriding revenue interests (“ORRI”) and working interest in individual wellbores as a means of securing financing for both corporate and field operations.

Prior to 2006, the Company has raised a total of $7,936,280 in funds from the sale of shares of common stock at $0.75 per share, and $17,265,375 from debt and revenue-sharing debt instruments.

In 2006, the Company sold 6,760,865 shares of common stock at $0.75 per share raising $5,050,650. Additionally, the Company raised $37,408,772 in debt from a private European equity firm, the Greater Europe Fund Limited and used these funds to satisfy the Company’s contractual obligations to Orchard Petroleum on the South Belridge California property, as well as acquire the Delhi Field Unit in Louisiana and the Stephens Field in Arkansas. The Company also raised $566,667 of funding through the issuance of debt with three parties in consideration for NRI in wells in Louisiana; $1,450,000 from the Riderwood Group for the issuance of debt in our California property which all converted to equity; $6,000,000 in debt issued to the sellers to acquire Days Creek; and an additional draw down of allocated work-over funds available from the asset-based financing of the Marion Field in the amount of $222,000. The Company issued debt to a Board member for the purchase of intellectual property in the amount of $3,650,000. Additionally, other funds were raised in 2006 consisting of the sale of two drilling rigs raising $1,550,000, and all of these those funds were used in the operation of the Company and its newly acquired fields.

 

In 2007, the Company sold 4,188,465 shares of common stock to investors at $0.75 per share raising $3,141,349. Additionally, the Company raised $1,582,333 through debt financing from its Executive Officers and Directors. In May 2007, the Company closed on the sale of certain wellbores, representing a portion of the Delhi Field Unit for cash proceed of $2,500,000. All funds raised in 2007 were used to support operations and continue our Phase Two drilling and well enhancement program.

 

Results of Operations

 

Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006

Oil and Natural Gas Revenues . Oil and natural gas revenues for 2007 and 2006 were $3,536,231 and $2,979,219, respectively, an increase of 18.7%. This increase was attributed to the acquisition of the Days Creek Field and the Delhi Field, which had revenues for 2007 of $565,774 and $360,860, respectively. This increase was also due to revenues from wells drilled in 2007 in the Belton Field and the Stephens Field of $59,760 and $44,613, respectively. These increases were offset by a decrease in the Marion Field revenues of $152,330 due to average natural gas price decrease, and by a decrease in the South Belridge Field revenues of $278,917 due to both oil and natural gas production declines year over year.

 

Drilling Revenues. Drilling revenues for 2007 and 2006 were $329,018 and $66,344, respectively. In fourth quarter 2006 the Company’s Tiger Bend Drilling, LLC subsidiary drilled one shallow well for a third party. The Company’s Tiger Bend Drilling, LLC subsidiary drilled two wells in the Stephens field, of which the Company holds a 24% working interest, during 2007 and the $329,018 in drilling revenues corresponds to the billings to the other working interest partners for drilling services.

 

License Fees, Royalties & Related Services. License fees, royalties and related services for 2007 and 2006 were $257,500 and $377,500, respectively, a decrease of $120,000. Licensing revenues increased from $125,500 for 2006 to $188,000 for 2007. These fees were associated with the granting of sectional and regional licensing of the Company’s proprietary lateral drilling technology. The Company believes that licensing revenues will decrease in the near future as the Company is not currently actively marketing sublicenses of its technology in favor of concentrating on internal field development, but believe that with ongoing in-house usage of the technology, there will be future opportunities to market the technology based on results documented by the Company. This increase was offset by a decrease in the sale of lateral drilling technology equipment from $252,000 for 2006 to $42,000 for 2007.

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Production and  Lease Operating Expenses. Production and lease operating expenses for 2007 and 2006 were $2,992,812 and $1,725,211, respectively, an increase of 73.5%. This increase was attributed to the acquisition of the Days Creek Field and the Delhi Field, which had a full twelve months of operations in 2007, for an increase of operating expenses of $534,092 and $501,911, respectively. These expenses included several initial well workovers, repair and maintenance of the existing infrastructure and equipment. Of the $231,598 remaining increase in operating expenses, $155,717 was due to two more wells on production for the full 2007 period in the South Belridge Field and $59,828 was due to increased operating costs in the Belton Field due to several new wells drilled in 2007.

 

Drilling Operating Expenses. Drilling operating expenses for 2007 and 2006 were $1,059,168 and $324,628, respectively. During the 2007 period the Company incurred $538,160 in subcontract labor, $67,620 in per diem costs, and $399,370 in rig fuel, maintenance and other operational costs to drill two deep wells in Arkansas in which the Company had a drill and completion 37.33% working interest and one well in Arkansas in which the Company had a drill and completion 100.0% working interest. The Company also incurred $400,000 during 2007 to lease a big drilling rig to use for these deep wells. This was an incremental cost to the prior year when the Company had owned its own drilling rigs. The Company spent 45 billable days drilling these three wells and capitalized $345,983 of the costs incurred to oil and gas properties as intangible drilling costs. The Company incurred two weeks of downtime because of drill stem reconditioning and mud pump repairs, and attributed approximately $105,000 of the costs incurred as expenses of keeping crews and the drilling rig active to hold circulation in the well. These costs could not be billed to working interest owners of the property and were recorded 100% as expense to the Company.

During the 2006 period the Company incurred $374,336 in subcontract labor, $31,918 in per diem costs, and $76,624 in rig fuel, maintenance and other operational costs to drill 4 shallow wells in Louisiana in which the Company had a 100% working interest and one shallow well in Louisiana for a third party. The Company spent 27 days drilling its own four shallow wells and capitalized $158,250 of the costs incurred to oil and gas properties as intangible drilling costs. The Company believes that $119,150 of these 2006 costs were attributed to start up costs of the drilling subsidiary company to train crews and repair the drilling rig in preparation for drilling work and were therefore expensed.

 

Costs Attributable to License Fees and Related Services. License fees and related service costs for 2007 and 2006 were $178,820 and $616,496, respectively, a decrease of 71.0%. The majority of the decrease is due to 2006 including $250,000 in licensing fees to the original technology owner during patent purchase negotiations. The decrease is also due to a $126,652 decrease in the cost basis of the lateral drilling technology equipment with less equipment sold in the 2007 period and is consistent with the decrease in related revenues. In addition the Company has decided to decrease this line of service, thus decreasing marketing and operational related expenses in 2007.

 

Exploration Costs. Exploration costs for 2007 and 2006 were $458,650 and $882,884, respectively, a decrease of $424,234 or 48.1%. This decrease was due to management’s election to curtail exploration activities due to the lack of available capital resources.

Revenue Sharing Royalties. Revenue sharing royalties for 2007 and 2006 were $165,418 and $389,757, respectively, a decrease of $224,339 or 57.6%. This decrease was due to production declines in the South Belridge Field resulting in lower overall net profits subject to distribution.

Depletion, Depreciation and Amortization. Depletion, depreciation, and amortization for 2007 and 2006 were $2,798,758 and $1,760,401, respectively, an increase of 59.0%. The increase was due to; the addition of $508,929 of amortization expense related to the purchased technology patent which was acquired in September 2006, the addition of $248,609 of depletion and depreciation from the Days Creek Field and Delhi Field acquisitions, the increase in depletion and depreciation of $129,439 from two new wells put on production in mid-2006 in the South Belridge Field, and the increase of $162,988 from the Marion Field due to a combination of two new wells on production, a downward revision in the depletable reserve basis and current year capital additions.

 

Impairment of Oil and Natural Gas Properties . Impairment of oil and natural gas properties for 2007 and 2006 was $7,445,367 and $4,843,688, respectively. Management performed its impairment evaluation of its long lived assets and determined that the South Belridge Field required an impairment charge of $7,195,367 and $4,843,688 in 2007 and 2006, respectively, due to the future cash flows from the Company’s interest in this field not being able to cover the cost basis of this property. The Company decided in 2007 not to pursue any prospects on the Medicine Lodge, Kansas property and has allowed all those leases to expire. Accordingly, the Company has recorded an impairment of $250,000 in 2007.

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Impairment of Investment . Impairment of investment for 2007 and 2006 was $1,365,712 and $179,400, respectively. The majority of the 2007 impairment was attributed by the Company’s decision not to go forward with the purchase of a fracturing technology that was initiated in 2006.  Having this technology available to the Company’s field teams is a major benefit in enhancing wells at a lower cost. This was the initial reason that the Company believed that owning the technology could provide additional cash flow as more service companies employed the technology worldwide. However, after a more profound analysis as to the cost-benefit of owning the technology as opposed to its standard operational use, and the need for significant funds to meet the Company’s Phase One plans and operational overhead, management determined that ownership of this intangible asset could not be fully attained without impairing the execution of the Company’s business plan. Management chose to stay focused singularly on its drilling plan and chose not to conclude the purchase, recognizing a $1,065,712 one-time loss representing advance payments towards the purchase price that were not refundable. In 2007 the Company also recorded an impairment of $225,000 to write-off costs spent on purchasing a pipeline in Kentucky that was abandoned in December 2007, and an impairment of $75,000 to write-off non-refundable costs spent pursuing the purchase of a third party’s sub-license of the LHD Technology, which was also abandoned in 2007.

Penalty for Late Payments to Operator . The Company incurred late payment penalty fees to the operator of the South Belridge Field for fiscal year 2006 of $2,152,501. The Company made cash payments totaling $1,152,501 and issued 1,333,333 shares of common stock valued at approximately $1,000,000 to the operator as “late fees.” The South Belridge Field has leasehold requirements of drilling 10 wells per year. Under that term of our JOA with the operator we were to provide 100% of the capital costs up to a certain limit, but when the Company could not meet cash call demands the operator had to fund these capital costs. When the Company became able to fund these commitments, the operator charged the Company a fee for their carrying cost of capital and a penalty for buying into wells already drilled.

 

Alternative Investment Market Fund Raising Activities. The Company incurred several pre-initial public offering costs over a one-year period straddling the 2005-2006 fiscal years as the Company investigated and attempted placement on the Alternative Investment Market (“AIM”) of the London Stock Exchange. AIM fund raising activities for 2006 were $2,666,587. AIM fund raising activities in 2006 mostly consisted of $1,271,183 of consulting services, of which $1,162,500 was recorded as the value of 1,550,000 shares of common stock issued for services. Costs of $680,274 in 2006 were incurred for two separate law firms and public accounting firms, one in the United States and one in the United Kingdom. Costs of $368,908 in 2006 were also incurred to secure a third party engineering assessment of the Company’s US based assets that would not have been required other than for this offering. In addition, these costs include $345,060 in 2006 of incremental increased travel and related expenses in opening and maintaining offices in London. The Company terminated its association with the London based broker for listing on the AIM when it became apparent that funding could not be secured under favorable terms and that tax issues would prove unattractive to all existing shareholders.

 

General and Administrative Expenses. General and administrative expenses for 2007 and 2006 were $8,644,418 and $8,157,225, respectively.  This net increase of $487,193 or 6.0% was the result of several offsetting factors. The major change came from payroll and associated expenses increasing by $831,726, primarily due to the 2007 year including 2.5 million shares of common stock valued at $1,875,000 issued to the former CEO pursuant to his employment agreement. This increase was offset by the 2006 year including accrued bonuses to three executive officers of $700,000. The majority of these bonus payments were deferred by the executives to assist the Company with its cash flow requirements. In addition, the 2006 year included a $306,000 payment and 250,000 stock options valued at $102,500 to a former director pursuant to a Separation Agreement. Payroll and associated expenses also increased over the 2006 year with the increase in employees from the Company hiring some of the consultants it had previously been contracting.

The change in general and administrative expenses was also due to legal and professional expenses increasing by $339,168 in 2007, primarily relating to the increased attorney fees and audit fees as the Company has prepared to become a public filer with the SEC. This was offset by a decrease in consulting services of $495,570 which was mainly due to three consultants becoming employees and the postponement of engineering services for the fields in 2007 that were incurred in the comparable 2006 year.  In addition, travel expenses declined by $490,331 due to the 2006 year including significant travel by management for fund raising purposes and due diligence on several property acquisitions.

 

Warrant Inducement  Expense . During 2006, in its effort to raise capital the Company issued warrants with an original exercise price of $0.75 per share, as investment incentives in raising over $17,000,000 in debt and equity funding. As a further incentive and to reduce the outstanding number of warrants, the Company offered these warrant holders the option of exchanging their warrants and issued four shares of common stock in exchange for every five warrants returned. In so doing the Company issued a total of 18,305,545 shares of common stock in the exchange, thereby eliminating approximately 22,915,255 warrants and the Company recorded $10,934,480 in other expenses as non-cash warrant inducement expense to account for the fair market value of this exchange.

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Interest Expense, net . Interest expense, net for 2007 and 2006 was $8,847,238 and $4,468,373, respectively. Interest expense related to debt increased $4,793,442 as the average outstanding balance increased over 2006 substantially from the full year outstanding of approximately $37,400,000 debt facility provided by Maxim TEP, Plc., a UK non-affiliated company to Maxim TEP, Inc., and controlled by the Greater Europe Fund Limited (“GEF”). The Company has subsequently repaid this debt and its corresponding accrued interest through the sale of the South Belridge Field and issuance of 21,700,000 shares of common stock in April 2008. Interest expense increased by $333,333 related to interest from stock put options issued in 2007 and effectively increased by $99,860 from a reduction in capitalized interest. These increases were offset by a decrease in the amortization of deferred financing costs of $683,127 and the amortization of debt discount of $208,209.

Income Taxes . There is no provision for income tax recorded for either 2007 or 2006 due to operating losses in both years. The Company has available Federal income tax net operating loss (“NOL”) carry forwards of approximately $79.8 million at December 31, 2007. The Company’s NOL generally begins to expire in 2026. The Company recognizes the tax benefit of NOL carry forwards as assets to the extent that Management believes that the realization of the NOL carry forward is more likely than not. The realization of future tax benefits is dependent on the Company’s ability to generate taxable income within the carry forward period. This valuation allowance is provided for all deferred tax assets.

 

Net Loss . The Company incurred a loss from operations for the year ended December 31, 2007 of $29,985,540 specifically due to reasons discussed above.

 

Plan		Interest			2007			2006
$4M Net Distribution (1)
Unrelated parties			9.00	%	$	11,490		$	14,513
Related parties			28.00	%		35,746			45,151
SB & Belton Field RSA (2)
Unrelated parties			5.36	%		17,283			27,626
Related parties			14.64	%		47,206			75,455
SB 7 Well Program (3)
Unrelated parties			4.78	%		3,685			19,620
Related parties			–	%		–			–
Marion Field RSA (4)
Unrelated parties			0.20	%		–			141
Related parties			1.20	%		–			845
Total					$	115,410		$	183,351

(1)	$4M Net Distribution provides participants a percentage of the first $4,000,000 per year of the Company’s net operating revenue. The net operating revenue subject to the net revenue sharing arrangement declines by 2.5% per annum beginning January 1, 2008 and terminates in 40 years.
(2)	SB & Belton Field RSA provides participants a net profits interest in the Company’s South Belridge Field and the original 3,008 acre lease of the Company’s Belton Field.
(3)	SB 7 Well Program provides participants a net profits interest in seven certain wells of the Company’s South Belridge Field.
(4)	Marion Field RSA provides participants a net profits interest in the Company’s Marion Field.

 

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Financing Arrangements

 

The Company continues to have strong cash needs to fund its drilling program and capital expenditures, as well as working capital. The Company is projecting a drilling and development budget of $12.4 million dollars for 2008. As part of its Phase Two, it will be necessary to raise additional capital to support current operations as well as needing capital for continued drilling and workovers to further develop the Company’s fields. Additionally, the Company will need working capital of approximately $6 million to pay third party engineers, subcontractors, and professional service providers, together with general overhead for 2008.  While there are no guarantees that it will be successful, the Company is currently in negotiations to acquire a portion of such funding from financial institutions and accredited investors. The Company is currently in default on certain of its debt obligations and the Company has no future borrowings or funding sources available under existing financing arrangements. If the Company is not successful in securing its 2008 funding for a drilling and development budget, some of the Company’s leases might be lost (see “Description of Fields” on Page 3) as well as the company may have to seek legal protection from creditors to protect its assets and assume additional losses in the process which at this point are difficult to forecast.  

 

The Company’s ability to obtain additional financing will be subject to a variety of uncertainties. The inability to raise additional funds on terms favorable to the Company could have a material adverse affect on its business, its financial condition and the results of its operations. If it were unable to obtain additional capital when required, the Company would be forced to make the necessary decisions to scale back operations and planned expenditures that would aversely affect its growth. There is no assurance that the current operating plan and growth strategy will be successful or that the Company will be able to complete its business plan’s goals, and thus possibly affecting the Company’s revenues and assets.

Production Payment Facility – Marion, Louisiana

During 2005, the Company entered into a production payment payable with a financial institution that provided for total borrowings up to $6,802,000. During 2005 and 2006, $6,275,000 and $220,000 was funded respectively. Of the proceeds received in 2005, $6,250,000 was used to acquire all the rights, title and interest in leases covering approximately 21,500 acres and 500 wellbores in the Monroe Gas Rock Field in Union Parrish, Louisiana (The Marion Field). Principal and interest will be paid out of production from the underlying property equal to 56% of the total revenues produced until an 18% internal rate of return is achieved. This production payment is secured by the Marion Field leases. During 2007 and 2006, production payments made to the financial institution were not sufficient to meet their internal rate of return of 18%. Therefore the outstanding balance of production payment payable was increased to accrue for the unpaid interest expense. At December 31, 2007, the Company has a total balance due of principal and interest to the financial institution of $6,877,945.

The Company has finalized its negotiations with BlueRock Energy Capital, Ltd (“BlueRock”) to restructure its monthly production payment facility on its Marion Field. The negotiations call for a reduction of the interest rate from its current 18% to 8% and to give back to the Company up to $25,000 of its production payment so that the field would be cash flow positive. The Company’s obligations under these new terms would be to seek refinancing of the production payment payable or the outright purchase of the production payable by no later than the anniversary of the agreement, should the Company not meet this obligation, BlueRock has the option of taking back the field in full payment of the production payment payable or revert back to the previous terms under the existing agreement.

 

Convertible Note By Owner Financing – Days Creek

During November 2006, the Company entered into three notes payable totaling $6 million, bearing interest at the rate of 10%, and maturing October 31, 2007, secured by the leases in the Days Creek Field. These notes payable are convertible into shares of the Company’s common stock at an exchange rate of $0.75 per share. If the note holders exercise their right to convert into the Company’s common stock, the Company will issue 8,000,000 shares of common stock. The notes payable are collateralized by the Company’s oil and gas property in the Days Creek Field and they provide for default interest at 15%. The Company has extended the maturity date of these notes payable to April 30, 2008. The company has an executed debt facility term sheet and is in the later stages of the due diligence process with an financial company for development, refinancing and acquisition funding, of which a portion of the proceeds are for the payment of the three notes payable totaling $6 million. The notes have been verbally extended to the date this funding goes forward and the proceeds are released, but in lieu of an executed agreement they are technically in default.

Lease Option Arrangements  (Kentucky & New Mexico)

The Company entered into lease option arrangements in the State of Kentucky to acquire additional property bordering, or adjacent to, it’s existing acreage of approximately 3,008 acres. Management has leased an additional 6,317 acres and believes that it has the potential to acquire an additional 11,855 acres or more, whose acquisition would add the potential for substantially more drilling sites. Similarly, Management believes that its field acquisition activities in New Mexico of a 2,080 acre parcel, will also offer a substantial number of potential drilling sites.

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South Belridge Field, Greater European Fund, Orchard Petroleum

In January 2005, the Company negotiated a joint operating agreement to acquire 960 acres in the South Belridge property in Kern County California to partner with Orchard Petroleum, Inc., an Australian-listed public company that would serve as operator since Orchard was already bonded to be an operator in the state of California. Maxim would have a 75% working interest of Orchard’s 75% working interest on the first phase of drilling as long as the Company tendered a promotion fee of $28.5 million. Maxim and Orchard would split operational costs 75:25 on this property, with the 25% balance held by the property owners. In an effort to raise funds in support of the ongoing California commitment Maxim secured funding from the Greater Europe Fund Limited (“GEF”), a private equity firm headquartered in Frankfurt. The Company’s loan facility with GEF and its affiliates provides for aggregate borrowings of $41.0 million, of which GEF lent a total of approximately $37.4 million. At December 31, 2007 the Company was in default on these notes payable but was in negotiations with the lender to repay this debt by selling a property.

During April 2008, the Company sold its South Belridge Field in a three party transaction that involved Mercuria Partners, a majority shareholder in Orchard Petroleum, and Maxim TEP PLC as an all inclusive deal to eliminate all debt, joint interest rights and obligations amongst all three parties, for a cash consideration of $35,846,346 and 21,700,000 shares of common stock in the Company to be issued to Maxim TEP PLC. With this cash and stock consideration, the Company will eliminate $37,408,772 in current note payable and approximately $6,100,000 in interest payable. Also, it will write down its net oil and gas assets by approximately $4,700,000. At the culmination of this transaction, the Company will have no further interest, rights or obligations in the South Belridge Field and will have satisfied in full all debt, interests and other obligations owed to Maxim TEP, PLC and its parent, the Greater European Fund, as well as any interest, rights or obligations under the Joint Venture agreement with Orchard Petroleum.

 

The fact that the Company is in default in some of its debt obligations could have a material adverse affect on its business, its financial condition and the results of its operations and put in question the Company’s ability to move forward as a going concern.

Effects of Inflation and Changes in Price

 

Our results of operations and cash flows are affected by changing oil and natural gas prices. If the price of oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in the operating cost that we are required to bear for operations, as well as an increase (decrease) in revenues. Inflation has had a minimal effect on the operating activities of the Company.

 

Recently Issued Accounting Pronouncements

 

In September 2006, the FASB issued SFAS No. 157, “ Fair Value Measurements”. This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements, where fair value has been determined to be the relevant measurement attribute. This statement is effective for financial statements of fiscal years beginning after November 15, 2007. The Company does not expect a material impact from SFAS No. 157 on its consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, “ The Fair Value Option for Financial Assets and Financial Liabilities including an amendment of FASB Statement No. 115 .” The new standard permits an entity to make an irrevocable election to measure most financial assets and financial liabilities at fair value. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied to the instrument in its entirety. Changes in fair value would be recorded in income. SFAS No. 159 establishes presentation and disclosure requirements intended to help financial statement users understand the effect of the entity’s election on earnings. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007. The Company does not expect a material impact from SFAS No. 159 on its consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “ Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) establishes principles and requirements to recognize the assets acquired and liabilities assumed in an acquisition transaction and determines what information to disclose to investors regarding the business combination. SFAS No. 141(R) is effective for business combinations for which the acquisition date is on or after the beginning of the first annual period beginning after December 15, 2008.

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In December 2007, the FASB issued SFAS No. 160, “ Non-controlling Interests in Consolidated Financial Statement—amendments of ARB No. 51.” SFAS No. 160 states that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity.  The statement also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners.  SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding non-controlling interest in one or more subsidiaries or that deconsolidate a subsidiary.  This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. The Company currently has no subsidiary subject to this standard and does not expect a material impact from SFAS No. 160 on its consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, “ Disclosures about Derivative Instruments and Hedging Activities”. SFAS 161 is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity’s financial position, financial performance, and cash flows. The provisions of SFAS 161 are effective for the fiscal years and interim periods beginning after November 15, 2008. The Company is currently evaluating the impact of adopting SFAS 161 on its consolidated financial statement disclosures.

On May 9, 2008 the FASB issued FASB Staff Position APB 14-1, “ Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)”. APB 14-1 requires the issuer to separately account for the liability and equity components of convertible debt instruments in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The guidance will result in companies recognizing higher interest expense in the statement of operations due to amortization of the discount that results from separating the liability and equity components. APB 14-1 will be effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The Company is currently evaluating the impact of adopting APB 14-1 on it consolidated financial statements.

Recently Adopted Accounting Pronouncements

 

During September 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109,” (“FIN 48”) which provides guidance for the recognition and measurement of a tax position taken or expected to be taken in a tax return. Under FIN 48, the Company is required to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. If the tax position meets the “more likely than not” recognition threshold, it is then measured and recorded at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.   The adoption of FIN 48 did not have a material effect on the Company’s consolidated financial position or results of operations.

Summary of Critical Accounting Policies

 

Use of Estimates

 

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

 

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of proved and unproved properties, future income taxes and related assets and liabilities, the fair value of various common stock, warrants and option transactions, and contingencies. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the calculation of impairment, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data, the engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

 

These significant estimates are based on current assumptions that may be materially effected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates, the fair value of the Company’s common stock and corresponding volatility, and the Company’s ability to generate future taxable income. Future changes to these assumptions may affect these significant estimates materially in the near term.

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Oil and Natural Gas Properties

 

We account for investments in natural gas and oil properties using the successful efforts method of accounting. Under this method of accounting, only successful exploration costs that directly result in the discovery of proved reserves are capitalized. Unsuccessful exploration costs that do not result in an asset with future economic benefit are expensed. All development costs are capitalized because the purpose of development activities is considered to be building a producing system of wells, and related equipment facilities, rather than searching for oil and gas. Items charged to expense generally include geological and geophysical costs. Capitalized costs of proved properties are depleted on a field-by-field (Common Reservoir) basis using the units-of-production method based upon proved, producing oil and natural gas reserves.

 

The net capitalized costs of proved oil and natural gas properties are subject to an impairment test based on the undiscounted  future net reserves from proved oil and natural gas reserves based on current economic and operating conditions. Impairment of an individual producing oil and natural gas field is first determined by comparing the undiscounted future net cash flows associated with the proved property to the carry value of the underlying property. If the cost of the underlying property is in excess of the undiscounted future net cash flows the carrying cost of the impaired property is compared to the estimated fair value and the difference is recorded as in impairment loss. Management’s estimate of fair value takes into account many factors such as the present value discount rate, pricing, and when appropriate possible and probable reserves when justified by economic conditions and actual or planned drilling or other development activities.

 

Under the successful efforts method of accounting, the depletion rate is the current period production as a percentage of the total proved producing reserves. The depletion rate is applied to the net book value of property costs to calculate the depletion expense. Proved reserves materially impact depletion expense. If the proved reserves decline, then the depletion rate (the rate at which we record depletion expense) increases, reducing net income.

 

We depreciate other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years.

 

Income Taxes

 

Under SFAS No. 109, “Accounting for Income Taxes,” deferred income taxes are recognized at each year end for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. We routinely assess the reliability of our deferred tax assets. We consider future taxable income in making such assessments. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, it is reduced by a valuation allowance. However, despite our attempt to make an accurate estimate, the ultimate utilization of our deferred tax assets is highly dependent upon our actual production and the realization of taxable income in future periods.

 

Contingencies

 

Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable.

 

Volatility of Oil and Natural Gas Prices

 

Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas.

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ITEM 3.  PROPERTIES

 

The Company has one primary facility located in The Woodlands, Texas. The Woodlands facility is 6,150 rentable square feet of office space. The Woodlands facility is occupied under a lease that commenced on November 1, 2004 and ends on October 31, 2009. Our rental expense for this facility is $10,763 per month for the first year and increases by $0.75 per square foot per year. The Company is obligated to pay their proportionate share of operating expenses of the property.

Additionally, the Company has acquired the following leases and mineral rights to recover oil and natural gas within the United States:

Belton Field - Muhlenberg County, Kentucky

In April 2004, the Company purchased the mineral rights on approximately 3,008 acres in Muhlenberg County Kentucky, an oil and gas field in the Illinois Basin, in west-central Kentucky. In 2006 and 2007, the Company leased the mineral rights to an additional 6,317 acres and is currently negotiating the lease of the mineral rights on an additional 11,855 acres. Oil was discovered in this basin about 150 years ago. When the Company acquired the rights on the original 3,008 acres, the above-the-ground pumping and storage units had fallen into disrepair and the field was idle. The field was originally discovered in 1939 and developed to produce oil from shallow zones. The first well was completed in the McClosky Limestone (TD 1,541’). Coal was discovered on the property and much of that coal was “mined-out” during strip mining operations. All mining operations ceased decades ago and the mines were reclaimed and are now pastures. Natural gas was discovered in the northwest corner of the field in the 1980s and continued to produce natural gas until recently. There are four known producing horizons on the property. These include (1) a shallow Pennsylvanian oil-bearing zone; (2) the upper-Mississippian oil-bearing Hardinsburg Sandstone; (3) the upper-Mississippian-period’s Jackson Sandstone that has significant gas indicated in two wells drilled on the northeast border of the property; and (4) the lower-Mississippian-period’s St. Genevieve Limestone (the oil-bearing McClosky zone). The Company’s drilling program includes the drilling of a significant number of new wells in this field in 2008.

The Marion Field - Union Parish, Louisiana

In December 2005, the Company leased shallow mineral rights (down to 3,200 feet) on approximately 21,500 acres in Union Parrish, Louisiana, which is a natural gas field currently producing revenues of $1.4 million annually from 476 wells, and with proved developed reserves of 1,788 MMcf. The Marion field is part of the larger Monroe Gas field which was the largest gas field in the United States in the early-to-mid 1900's. It should be noted that in 2005 state records indicated that the Monroe Gas Field produced over 7.0 Tcf. It is located in Northeast Louisiana, in Union Parish which has 8,558 wells. The oil producing Cotton Valley and Smackover formations are also present within the leasehold. In addition, in December 2005, the Company leased deep mineral rights (down to 9,500 feet) on approximately 8,000 acres of the 21,500 acres that will allow the Company to explore this deeper zone. The Company believes that existing oil and gas prices, together with new techniques for stimulating production will make additional drilling and well workover activities in this field commercially viable.

The Delhi Field - Richland Parish, Louisiana

In December 2006, the Company acquired mineral right leases on 1,400 acres in the Delhi Field, in north-east Louisiana. The Company’s lease encompasses a portion of approximately 13,636 acres comprising the Delhi Holt Bryant Unit and Mengel Unit. Oil production in this field has traditionally utilized 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. Water is produced primarily from the Holt Bryant and injected into the Mengel. The Company believes that improper placement of injection wells has created reservoir channeling and is not sweeping the oil from the majority of the formation. The Company’s 2008 drilling program involves converting existing wellbores to water injection wells, repairing shut-in wells, using new technology and replacing inefficient downhole pumps, all of which the Company believes will enhance the efficiency of the waterflood and increase production while allowing a higher percentage of residual oil to be produced.

The Days Creek Field - Miller County, Arkansas

In November 2006, the Company acquired a mineral rights lease on 740 acres in Miller County, Arkansas in the Days Creek Field. The field was originally discovered by American Petro Fina in 1972. According to state records, the cumulative production from this field has been approximately 8.6 million barrels of oil and 6 BCF of natural gas. The primary zone is the Smackover limestone at approximately 8,100 - 8,500 feet. Currently there are four producing oil wells. The Norphlet Sand is present at deeper depths between 8,900 and 11,000 feet. Seismic data in the area indicates the possibility of oil and gas productive potential in this zone.

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The Stephens Field at Smackover - Ouachita County, Arkansas

In January 2007, the Company acquired a mineral rights lease on approximately 1,300 acres in Ouachita County, Arkansas with access to the Smackover formation. Smackover production is widespread and prolific in this section of the state. It is nearby at Stephens to the north and at McNeil to the south. Modern gamma ray-neutron/density logs show the presence of oil and gas in many of the 40 to 50 sands in the Travis Peak and Cotton Valley sections from 3,000 to 6,000 feet.

Hospah, Lone Pine & Clovis Field - McKinley County, New Mexico

In 2006 and 2007, the Company acquired mineral rights leases on approximately 2,080 acres in the Hospah Field and Lone Pine Field in McKinley County, New Mexico. The Company is currently negotiating to acquire a 100% working interest and an 80% net revenue interest on an additional 1,280 acres in the Clovis field. The Hospah Field was discovered in 1924 and has produced oil for many years. The Upper Hospah Sandstone of Cretaceous Age produced 5 million barrels by 1974. The Lone Pine Field was found just south of Hospah in 1970 and oil was discovered from the productive Dakota Sandstone at a depth of between 2,500 and 3,800 feet. Most of all the oil development in these fields was done by Tenneco. Oil and gas production from the Hospah Sandstones reservoirs from 1927 to 2005 has yielded nearly 22 million barrels of oil and nearly 53 Mcf of gas.

South Belridge Field, Kern County, California

In 2005, Maxim negotiated a JOA with Orchard Petroleum, Inc. to participate in Orchard’s drilling operations on a prospect of approximately 960-acre in Kern County, California. In early 2007, the Company paid $500,000 for a 50% working interest in 600 acres of section 18 which is adjacent to the original 960 acre prospect. The South Belridge field was discovered in April of 1911 with the completion of Well No. 101 by Belridge Oil Company. In December 1979, Shell Oil Company purchased Belridge Oil Company and the majority of South Belridge production for $3.65 billion. Originally considered to be a minor field in 1995, the South Belridge field reached one billion barrels of cumulative oil production, the sixth field in California to do so and the 15th field in the nation. By supporting Orchard’s drilling operations the Company believes that it could monetize this property to assist in resolving some of the Company’s debt. In April 2008 the Company sold South Belridge in order to reduce indebtedness.

Medicine Lodge Field, Medicine Lodge, Kansas

Maxim acquired a section of property, 640 acres, as partial consideration of a lawsuit settlement in 2005. The Company decided not to develop this field and allowed the leases to expire in late 2007 and early 2008.

Oil and Natural Gas Reserve Estimates

For information relating to: Reserves; Costs Incurred; Drilling Activity; Productive Wells; and Acreage, please refer to ITEM 1. Description of Business, Sections (C) and (D), beginning on page 3.

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ITEM 4.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL  OWNERS AND MANAGEMENT

 

Beneficial ownership is determined in accordance with the rules of the SEC, and generally includes voting power and/or investment power with respect to the securities held. Shares of common stock subject to options currently exercisable or exercisable within 60 days of May 31, 2008 are deemed outstanding and beneficially owned by the person holding such options for purposes of computing the number of shares and percentage beneficially owned by such person, but are not deemed outstanding for purposes of computing the percentage beneficially owned by any other person. Except as indicated in the footnotes to these tables, and subject to applicable community property laws, the persons or entities named have sole voting and investment power with respect to all shares of our common stock shown as beneficially owned by them.

Name and Address of Beneficial Owner		Common Stock Beneficially Owned			Percentage of Class
Maxim TEP Limited			21,700,000			17.3	%
1 London Wall
London EC 2Y 5AB
Harvey Pensack (1)			12,352,421			9.6	%
7309 Barclay Court
University Park, FL 34201
Carl Landers (2)			7,275,000			5.8	%
141 S. Union Street
Madisonville, KY 42431
Robert McCann (3)			6,618,334			5.3	%
160 Yacht Club Way
Hypoluxo, FL 33462

 

(1) Includes (i) 1,216,250 shares issuable pursuant to outstanding warrants, (ii) 450,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008, and (iii) 1,818,182 shares of voting preferred stock. Also includes 3,983,779 shares held by the Harvey Pensack Revocable Living Trust of which Mr. Pensack is a trustee, and 2,228,042 shares held by Joan Pensack, Mr. Pensack’s wife.

 

(2) Includes 600,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.

(3) Includes 150,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.

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Name and Address of Beneficial Owner		Common Stock Beneficially Owned			Percentage of Class
Harvey Pensack (1)			12,352,421			9.6	%
7309 Barclay Court
University Park, FL 34201
Carl Landers (2)			7,275,000			5.8	%
141 S. Union Street
Madisonville, KY 42431
W. Marvin Watson (3)			5,566,549			4.4	%
9400 Grogan’s Mill Road, St 205
The Woodlands, TX 77380
Dr. John P. Ritota, Jr. (4)			4,126,667			3.2	%
919 Seagate Drive
Delray Beach, FL 33483
Dan Williams (5)			3,105,528			2.5	%
594 Sawdust Road #382
The Woodlands, TX 77380
Eugene Fusz   (6)			2,669,232			2.1	%
223 Park Avenue
Palm Beach, FL 33401
Robert Sepos (7)			2,835,877			2.2	%
87 Robindale Circle
The Woodlands, TX 77382
John J. Dorgan (8)			1,965,675			1.6	%
555 Byron Street
Palo Alto, CA 94301
Dominick F. Maggio (9)			1,300,339			1.0	%
2205 Riva Row, Suite 2113
The Woodlands, TX 77380
Robert D. Johnson (10)			1,695,768			1.3	%
13606 Bermuda Dunes Court
Houston, TX 77069
Steve Warner (11)			1,025,000			0.8	%
400 N Flagler Drive, #1601
Delray Beach, FL 33401
Glenn Biggs (12)			550,397			0.4	%
1208 South Main Street
Boerne, TX 78006
All Directors and officers as a group (12) persons			44,468,453			32.2	%

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(1)	Includes (i) 1,216,250 shares issuable pursuant to outstanding warrants, (ii) 450,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008, and (iii) 1,818,182 shares of voting preferred stock. Also includes 3,983,779 shares held by the Harvey Pensack Revocable Living Trust of which Mr. Pensack is a trustee, and 2,228,042 shares held by Joan Pensack, Mr. Pensack’s wife.
(2)	Includes 600,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.
(3)	Includes (i) 2,500 shares issuable upon exercise of warrants, and (ii) 600,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.
(4)	Includes (i) 1,650,000 shares issuable upon exercise of outstanding warrants, and (ii) 600,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.
(5)	Includes 450,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008. Also includes 125,000 shares held by the Matthew Williams Irrevocable Trust of which Mr. Williams is a trustee.
(6)	Includes 550,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008. Also includes 2,119,232 shares held by the Eugene Fusz Trust dtd 9/16/05 of which Mr. Fusz is a trustee.
(7)	Includes (i) 206,666 shares held by The Sepos Family Limited Partnership of which Mr. Sepos is the general partner, and (ii) 1,000,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.
(8)	Includes (i) 1,375,000 shares issuable pursuant to options exercisable within 60 days of May 31,2008.
(9)	Includes (i) 300,339 shares held by AMDG Incorporated, a company controlled by Mr. Maggio, and (ii) 1,000,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.
(10)	Includes 547,456 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.
(11)	Includes 300,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.
(12)	Includes 300,000 shares issuable pursuant to options exercisable within 60 days of May 31, 2008.

 

ITEM 5.  DIRECTORS AND EXECUTIVE OFFICERS

 

The following is a list of the directors and executive officers of the Company on May 31, 2008.

 

Name		Age		Position		Year First Elected or Appointed
W. Marvin Watson		83		Chairman of the Board, CEO		2004
Carl Landers		63		Director		2004
Harvey Pensack		84		Director		2004
John P. Ritota		57		Director		2004
Robert Johnson		61		Director, President		2008

At the beginning of 2007, Mr. Steve Warner and Mr. Eugene Fusz served on the Company’s Board of Directors, but at the Company’s April 2007 shareholders meeting, they were not re-nominated to the Board of Directors.

During the fourth quarter of 2007, the Company's Chief Executive Officer stepped down and was replaced by a member of the Board of Directors. Furthermore, the Chief Financial Officer was reassigned to the position of Chief Operations Officer and his former position filled by an experienced and reputable third party.

During January 2008, the Company restructured its management and terminated its Chief Operations Officer and Chief Information Officer in addition to certain employees whose positions had been combined with the remaining workforce.

In May of 2008, Mr. Glenn Biggs and Mr. Jack Dorgan stepped down from the Board of Directors, both citing personal reasons.

In May of 2008, the Company hired Mr. Robert Johnson, an experienced oil and gas executive, as Director, President and Chief Operating Officer of the Company.

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Business Experience and Background of Directors and Executive Officers   

 

W. MARVIN WATSON , Chairman of the Board and CEO

Mr. Watson became a member of the Company’s Board of Directors on March 10, 2004 and has served as Chairman of the Company’s Board of Directors since April 2006, and assumed the position of Chief Executive Officer on October 3, 2007. After serving in the U.S. Marine Corps during World War II, Mr. Watson earned a Bachelors of Business Administration from Baylor University and a Masters of Art in Economics from Baylor. From 1956-1965 he served as Executive Assistant to the President of Lone Star Steel Company in Dallas, Texas. From 1965-1968, Mr. Watson was a special advisor to the President Lyndon Baines Johnson and served as President Johnson’s Chief of Staff. In 1968, President Johnson named him to a Cabinet-level position as U.S. Postmaster General. In March 1969 Mr. Watson accepted the presidency of Occidental International Corporation, a subsidiary of Occidental Petroleum Corporation. In 1971, he was appointed Senior Vice President and elected to the Board of Occidental Petroleum. Soon thereafter he was elected Executive Vice President, and as one of two Executive Vice Presidents, assumed the responsibility of the President’s position at the parent company of Occidental. He served as Chairman of the Board or President of the subsidiaries of Occidental, and during his tenure, the company grew from the 22nd largest to the 9th largest U.S. Corporation according to a national publication. From 1979-1987 Mr. Watson served as President and CEO of Dallas Baptist University. From 1991-1993, he was Chairman of Polish Telephones and Microwave Corporation, and from 1996-1998 President/CEO of Radopath Pharmaceuticals Corporation. During 2003 and 2004, Mr. Watson, finalized his memoirs of his time spent in the Lyndon Johnson White House, entitled “Chief of Staff – Lyndon Johnson and His Presidency” , which were published in the fall of 2004. From 2004 until he became a member of the Company’s Board of Directors, Mr. Watson participated in book tours and public speaking engagements and was active in the management of personal investments. From June 1, 2005 until October 3, 2007, Mr. Watson served as director of development and corporate structure for Maxim TEP, Inc.

CARL LANDERS , Director

Mr. Landers was appointed to the Company’s board of directors in January 2004. Mr. Landers is an independent oil and gas producer and inventor. Carl Landers is the inventor of the Landers Lateral Horizontal Drilling (“LHD”) technology, and has been instrumental in bringing a contrarian approach to the energy industry. More than 300 wells have been completed utilizing the LHD patented technology. In 1993, Mr. Landers founded Advanced Petroleum Inc, an oil services company focused on refining LHD, and has been president of the company since founding. In 2004, Mr. Landers founded Advanced Methane Recovery, LLC, an energy company focused on the recovery of shale and coal bed methane, and has been manager of the company since founding.

JOHN P. RITOTA, JR., D.D.S.,  Director

Dr. Ritota was appointed to the Company’s board of directors in January 2004. He was a founding shareholder of Alpha Pro Tech, Inc. in 1990 (AMEX:APT) a company that designs and manufactures a wide range of products to meet requirements in the healthcare, industrial, laboratory, clean room, foodservice, pet and other markets, which are now marketed worldwide. Since 1991, he has served as Executive Director of the Audit Committee, and Chairman of the Compensation Committee of Alpha Pro Tech. Dr. Ritota was an original investor in CompuPix, one of the first developers of high definition television (HDTV), and Orrox, a company that offered one of the first eighteen-inch satellite dishes. Dr. Ritota graduated from Ithaca College in June 1971, and earned his Doctor of Dental Science at Georgetown University in May 1975. Since April 1981, Dr. Ritota has shared an active practice in General Dentistry with his brother, Dr. Ted Ritota, in Delray Beach, Florida.

HARVEY M. PENSACK,  Director

Mr. Pensack was appointed to the Company’s board of directors on September 24, 2004. After graduating Cum Laude from Clarkson University in 1944, with a B.S. Degree in Mechanical Engineering, Mr. Pensack served in the military, finishing as a First Lieutenant in 1946. He spent seven years in the insurance industry earning promotions and supervisory positions but then saw the potential in the young computer industry. In 1953, utilizing his engineering training and entrepreneurial spirit, he founded Mitronics Inc., an innovative manufacturer of hermetic ceramic-to-metal seals for the then-fledgling semiconductor industry. Mr. Pensack served as Chairman and CEO of Mitronics, which was merged into a public corporation to become Varadyne, Inc. in 1970. Throughout the 1970s, 1980s and 1990s, Mr. Pensack had an active career as a financial consultant specializing in insurance, business succession planning and estate management. During the past five years Mr. Pensack has primarily been engaged in the management of personal investments. Throughout his career, Mr. Pensack has been quick to recognize potential in many diverse fields, and has been a private investor who specializes in researching and analyzing potential investment choices with a focus on management personnel and growth opportunity.

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ROBERT JOHNSON , Director/President and Chief Operating Officer

Mr. Johnson joined the Company in May of 2008. He brings with him over 40 years of experience in the oil and gas sector. Mr. Johnson graduated with a Bachelor of Science Degree in Petroleum Engineering from Louisiana State University in 1969. He joined Amoco Production Company upon leaving school. In 1970, he entered the United States Army and served for nearly two years. He rejoined Amoco in 1971 and rose rapidly through the ranks. His final position was Regional Engineering Manager over 250 engineers. He left Amoco in 1980 and joined Superior Oil Company as Division Drilling Engineering Manager for the Western half of the United States. In 1981, he left Superior and formed Conquest Petroleum Incorporated as the Founder and Chief Executive Officer. After securing funding to acquire 68,000 acres of leases in the Texas State Waters and promoting the acreage on 27 prospects to outside 3rd parties. Conquest had five discoveries, then he divested the assets and dissolved the company in 1985 due to insufficient product prices. He formed Bannon Energy Incorporated in 1986 with an initial capitalization of $1,000. During the next 10 years, Bannon acquired 12 sets of producing properties and drilled over 284 development wells. He sold the assets of Bannon in 1996 for $38,000,000 and other considerations. Mr. Johnson dissolved Bannon in February of 2001.  From February of 2001 until May of 2008 when he joined the company as President and Chief Operating Officer, he was officially in full retirement.

Involvement in Certain Legal Proceedings

The foregoing directors or executive officers have not been involved during the last five years in any of the following events:

 

·

Bankruptcy petitions filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time;

·

Conviction in a criminal proceeding or being subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);

 

·

Being subject to any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring or suspending or otherwise limiting his involvement in any type of business, securities or banking activities; or

·

Being found by a court of competition jurisdiction (in a civil action), the Securities and Exchange Commission or the Commodities Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended or vacated.

Board Composition and Committees

 

Our business and affairs are organized under the direction of our board of directors, which currently consists of five members. The primary responsibilities of our board of directors are to provide oversight, strategic guidance, counseling and direction to our management. Our board of directors meets on a regular basis and additionally as required. Written board materials are distributed in advance as a general rule, and our board of directors schedules meetings with and presentations from members of our senior management on a regular basis and as required.

 

Our board of directors has established an audit committee, a compensation committee and a nominating/corporate governance committee. Our board of directors and its committees set schedules to meet throughout the year and also can hold special meetings and act by written consent under certain circumstances. Our board of directors has delegated various responsibilities and authority to its committees as generally described below. The committees will regularly report on their activities and actions to the full board of directors. Each member of each committee of our board of directors is currently not bound to be an independent director but the Company will be in compliance with the guidelines set by the public market onto which it ultimately lists. Each committee of our board of directors is reviewing written charters, which when complete, will be subject to approval by our board of directors. Upon the effectiveness of this registration statement, copies of each charter will be posted on our website at www.maximtep.com under the Investor Relations section. The inclusion of our website address in this Registration Statement does not include or incorporate by reference the information on our website into this Registration Statement.

Director Independence

Our board of directors is made up of W. Marvin Watson, our Chairman and Chief Executive Officer, Robert Johnson, our President, and Directors Carl Landers, Dr. John Ritota, and Harvey Pensack. Our common stock is not traded on any public markets, and we are not currently subject to corporate governance standards of listed companies, which require, among other things, that the majority of the board of directors be independent. However, if the Company were subject to the independence requirements of the Nasdaq, for example, Dr. John Ritota, would be the only director to qualify as independent under the standard set forth by the Nasdaq.

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Audit Committee

 

The audit committee of our board of directors oversees our accounting practices, system of internal controls, audit processes and financial reporting processes. Among other things, our audit committee is responsible for reviewing our disclosure controls and processes and the adequacy and effectiveness of our internal controls. It also discusses the scope and results of the audit with our independent auditors, reviews with our management and our independent auditors our interim and year-end operating results and, as appropriate, initiates inquiries into aspects of our financial affairs. Our audit committee has oversight for our code of business conduct and is responsible for establishing procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls or auditing matters, or matters related to our code of business conduct, and for the confidential, anonymous submission by our employees of concerns regarding such matters. In addition, our audit committee has sole and direct responsibility for the appointment, retention, compensation and oversight of the work of our independent auditors, including approving services and fee arrangements. Our audit committee also is responsible for reviewing and approving all related party transactions in accordance with our policies and procedures with respect to related person transactions.

 

The current members of our audit committee are Dr. John Ritota, Jr. and Mr. Carl Landers. Messrs. Ritota and Landers are not currently required to be independent for audit committee purposes. If the Company were subject to the independence requirements of the Nasdaq, none of the members of the audit committee would qualify as independent under the standard set forth by the Nasdaq. Dr. John Ritota is the chairman of the audit committee. We intend to comply with the appropriate public market requirements prior the first anniversary of the completion of this registration statement.

 

Compensation Committee

 

The members of our compensation committee are Mr. Carl Landers and Dr. John Ritota. Mr. Landers chairs the compensation committee. The purpose of our compensation committee is to have primary responsibility for discharging the responsibilities of our board of directors relating to executive compensation policies and programs. Among other things, specific responsibilities of our compensation committee include evaluating the performance of our chief executive officer and determining our chief executive officer’s compensation. In consultation with our chief executive officer, it will also determine the compensation of our other executive officers. In addition, our compensation committee will administer our equity compensation plans and has the authority to grant equity awards and approve modifications of such awards under our equity compensation plans, subject to the terms and conditions of the equity award policy adopted by our board of directors. Our compensation committee also reviews and approves various other compensation policies and matters.

 

Nominating/Corporate Governance Committee

 

The members of our nominating/corporate governance committee are Mr. Carl Landers and Dr. John Ritota. Dr. Ritota chairs the nominating/corporate governance committee. The nominating/corporate governance committee of our board of directors oversees the nomination of directors, including, among other things, identifying, evaluating and making recommendations of nominees to our board of directors and evaluates the performance of our board of directors and individual directors. Our nominating/corporate governance committee is also responsible for reviewing developments in corporate governance practices, evaluating the adequacy of our corporate governance practices and making recommendations to our board of directors concerning corporate governance matters.

 

Limitation of Liability and Indemnification

 

We intend to enter into indemnification agreements with each of our directors and executive officers and certain other key employees. The form of agreement provides that we will indemnify each of our directors, executive officers and such other key employees against any and all expenses incurred by that director, executive officer or key employee because of his or her status as one of our directors, executive officers or key employees, to the fullest extent permitted by Texas law, our articles of incorporation and our bylaws (except in a proceeding initiated by such person without board approval). In addition, the form agreement provides that, to the fullest extent permitted by Texas law, we will advance all expenses incurred by our directors, executive officers and such key employees in connection with a legal proceeding.

 

Our articles of incorporation and bylaws contain provisions relating to the limitation of liability and indemnification of directors and officers. The articles of incorporation provide that our directors will not be personally liable to us or our stockholders for monetary damages for any breach of fiduciary duty as a director.

Our bylaws provide that we will indemnify our directors and officers to the fullest extent permitted by Texas law, as it now exists or may in the future be amended, against all expenses and liabilities reasonably incurred in connection with their service for or on our behalf. Our bylaws provide that we shall advance the expenses incurred by a director or officer in advance of the final disposition of an action or proceeding. Our bylaws also authorize us to indemnify any of our employees or agents and permit us to secure insurance on behalf of any officer, director, employee or agent for any liability arising out of their action in that capacity, whether or not Texas law would otherwise permit indemnification.

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ITEM 6.

EXECUTIVE COMPENSATION

 

The following table sets forth the total compensation awarded to, earned by, or paid to our “principal executive officer,” and our other named executive officers for all services rendered in all capacities to us in 2007 and 2006.

														Warrant and
Name and					Contract						Stock			Option			All Other
Principal Position		Year			Salary (1)			Contract Bonus			Awards (2)			Awards (3)			Compensation (4)			Total
W. Marvin Watson			2006		$	240,000		$	–		$	813,500		$	70,800		$	11,679		$	1,135,979
Chairman/President
Director of Development & Corporate Structure (5)			2007		$	385,000		$	–		$	–		$	44,469		$	11,980		$	441,449
Daniel Williams			2006		$	350,000		$	300,000		$	–		$	70,800		$	18,004		$	738,804
Chief Executive Officer (6)(8)			2007		$	300,000		$	–		$	1,875,000		$	43,950		$	15,656		$	2,234,606
Robert Sepos			2006		$	300,000		$	200,000		$	–		$	–		$	14,921		$	514,921
VP/Chief Operating Officer (7)(8)(9)			2007		$	300,000		$	–		$	–		$	–		$	19,677		$	319,677
Dominick F. Maggio			2006		$	300,000		$	200,000		$	–		$	–		$	17,176		$	517,176
VP/Chief Information Officer (8)(9)			2007		$	300,000		$	–		$	–		$	–		$	23,584		$	323,584

 

All Other Compensation - 2006		Watson			Sepos			Maggio			Williams
Car Allowance		$	11,679		$	7,044		$	8,851		$	7,006
Life Insurance			–			7,877			8,325			10,998
		$	11,679		$	14,921		$	17,176		$	18,004

All Other Compensation - 2007		Watson			Sepos			Maggio			Williams
Warrants		$	733		$	–		$	–		$	–
Car Allowance			11,247			7,284			9,345			11,753
Life Insurance			–			12,393			14,239			3,903
		$	11,980		$	19,677		$	23,584		$	15,656

 

(1)	Bonuses were components of Employee Agreements, the majority of which payments were deferred by all the Executives to assist the Company with cash flow requirements.
(2)	Amounts represent the dollars recognized for financial statement reporting purposes with respect to the fiscal year  in accordance with SFAS No. 123(R). See Note 2 of the notes to consolidated financial statements  included elsewhere in this Registration Statement for a discussion of our assumptions in determining the SFAS No.123(R) fair values of our stock awards, valued at $0.75 per share.
(3)	Amounts represent the dollars recognized for financial statement reporting purposes with respect to the fiscal year  in accordance with SFAS No. 123(R) excluding forfeiture estimates. See Note 2 of the notes to consolidated financial statements  included elsewhere in this Registration Statement for a discussion of our assumptions in determining the SFAS No.123(R) fair values  of our warrant and option awards.
(4)	This column represents Company payments towards life insurance for executive officers and auto allowances capped at $1,000 monthly.
(5)	W. Marvin Watson was the Director of Development & Corporate Structure from June 1, 2005 until he assumed the role of Chief Executive Officer effective October 3, 2007.
(6)	Daniel Williams stepped down as President/CEO on October 3, 2007.
(7)	Robert Sepos served as the Company's Chief Financial Officer until October 29, 2007 when he assumed the role of Chief Operating Officer.
(8)	Officers Williams, Maggio and Sepos deferred 2/3 of their salary from November 2006 to December 2007 to assist the Company with cash flows.
(9)	As a part of the Company's 2008 restructuring Messrs. Maggio and Sepos were terminated.

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On June 1, 2005, the Company entered into an employment agreement with W. Marvin Watson to oversee the development of the corporate structure. The agreement was for four years ending June 1, 2009 at a base salary of $240,000, housing during relocation, an automobile and provided for a grant of 1,000,000 warrants, exercisable at $0.75 per share for a period of five years. The contract included severance pay if termination occurs (i) within one year of the effective date, an amount equal to six month’s base salary; (ii) after one year but prior to completion of second year from the effective date an amount equal to twelve month’s base salary; (iii) after two years or any time thereafter from the effective date an amount equal to fifteen month’s base salary.

 

On October 3, 2007, the Company entered into an addendum to Mr. Watson’s employment agreement, elevating his position to Chief Executive Officer. The agreement increased the initial term of employment by two years to October 2, 2011, continued automobile and raised Mr. Watson’s base salary to $385,000. The base salary would increase to $435,000 after the first anniversary of the effective date of October 3, 2007 and to $485,000 after the second anniversary of the effective date. Mr. Watson was granted 3,300,000 shares of the Company’s common stock in 2008. Mr. Watson will be entitled to receive bonuses based on annual performance of the Company and at the discretion of the Board

 

On June 1, 2006, the Company entered into employment agreements with three officers of the Company: Daniel Williams to serve as President/Chief Executive Officer, Robert Sepos to serve as Executive Vice President/Chief Financial Officer, and Dominick Maggio to serve as Vice President and Chief Information Officer. All of the agreements are for five years ending June 1, 2011 and allow the officers to be eligible for an annual bonus as determined by the Audit Committee of the Board. Daniel Williams’s employment agreement includes an annual base salary of $350,000. Robert Sepos’s and Dominick Maggio’s employment agreements include an annual base salary of $300,000.

Mr. Williams resigned as CEO of the company on October 3, 2007 and is contracted as a consultant on an as needed basis. Due to his resignation, there was no severance or other compensation. Both Messrs. Maggio and Sepos were terminated as part of a reorganization and restructuring of the Company. The Company has reached a settlement agreement with both Messrs Maggio and Sepos. As a result of these settlement agreements the Company will honor both Messrs Maggio and Sepos’s 1,000,000 stock options per their employment agreements. In addition, Mr. Maggio promises to pay back the Company $300,000 with an 8% interest rate collateralized by stock in the Company and Mr. Sepos promises to pay back the Company $6,000 with an 8% interest rate collateralized by his stock in the Company. 

Outstanding Equity Awards at Fiscal Year End

 

The following table sets forth information regarding each unexercised option held by each of our fiscal year 2007 named executive officers as of December 31, 2007.

Name

No. of Securities Underlying Unexercised Options Exercisable   (1)

No. of Securities Underlying Unexercised Options Unexercisable

Option Exercise Price

Option Expiration Date

W. Marvin Watson

450,000

–

$

0.75

06/21/2012

Daniel Williams

150,000

–

$

0.75

06/21/2012

Dominick F. Maggio

–

–

$

–

–

Robert Sepos

–

–

$

–

–

 

(1)	These options were fully vested on the date of grant.

 

Director Compensation

 

The following table sets forth the total compensation awarded to, earned by, or paid to each person who served as a director during fiscal year 2007, other than a director who also served as a named executive officer. Our directors who are not executive officers did not receive any cash compensation during 2007 for serving on our board of directors. We have a policy of reimbursing our directors for their reasonable out-of-pocket expenses incurred in attending Board and committee meetings. Pursuant to the terms of our 2005 Incentive Compensation Plan, each director upon appointment or election to the board is entitled to receive an option to acquire 150,000 shares of Common Stock on the date elected with an exercise price of $0.75 per share. In addition, for as long as the 2005 Incentive Compensation Plan remains in effect and shares of Common Stock remain available for issuance there under, each director serving on the Board shall automatically be granted an option to acquire 150,000 shares of Common Stock, with an exercise price of $0.75 per share, each year.

Name		Stock Option Awards   (1)			Stock Warrant Awards			Total
Carl Landers		$	43,950		$	–		$	43,950
John J. Dorgan		$	43,950		$	–		$	43,950
Harvey Pensack		$	43,950		$	14,600	(2)	$	58,550
John P. Ritota		$	43,950		$	606,000	(3)	$	649,950
Raymond Gill		$	43,950		$	–		$	43,950
Glenn Biggs		$	63,450		$	–		$	63,450
Steve Warner		$	–		$	–		$	–
Eugene Fusz		$	–		$	–		$	–

 

(1)	Amounts represent the dollar amount recognized for financial statement reporting purposes with respect to the fiscal year in accordance with SFAS No. 123(R) excluding forfeiture estimates. See Note 2 of the notes to consolidated financial statements included else where in this Registration Statement for a discussion of our assumptions in determining the SFAS No.123(R) fair values of our option awards.
(2)	Mr. Pensack received 50,000 warrants with an exercise price of $0.75 per share for the extension of note payable.
(3)	Mr. Ritota received 2,000,000 warrants with an exercise price of $0.75 per share for fund raising services.

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Equity Benefit Plans

 

2005 Incentive Compensation Plan

 

The Company adopted the 2005 Incentive Compensation Plan on May 13, 2005.

 

Share Reserve . We reserved 5,000,000 shares of our common stock for issuance under the 2005 Incentive Compensation Plan on May 13, 2005. On March 21, 2007, the Board of Directors amended the Plan to increase the number of shares reserved for issuance thereunder to 15,000,000 shares. On December 5, 2007, the Board of Directors amended the Plan to increase the number of shares reserved for issuance there under to 30,000,000 shares. In general, to the extent that awards under the 2005 Incentive Compensation Plan are forfeited or lapse without the issuance of shares, those shares will again become available for awards. All share numbers described in this summary of the 2005 Incentive Compensation Plan (including exercise prices for options) are automatically adjusted in the event of a stock split, a stock dividend, or a reverse stock split.

Administration . The board of directors administers the 2005 Incentive Compensation Plan. The board of directors may delegate its authority to administer the 2005 Incentive Compensation Plan to a committee of the Board. The administrator of the 2005 Incentive Compensation Plan has the complete discretion to make all decisions relating to the plan and outstanding awards.

 

Eligibility. Employees, members of our board of directors and consultants are eligible to participate in our 2005 Incentive Compensation Plan.

Types of Award . Our 2005 Incentive Compensation Plan provides for the following types of awards:

	·	incentive and non-qualified stock options to purchase shares of our common stock;
	·	restricted shares of our common stock.

 

Options. The exercise price for options granted under the 2005 Incentive Compensation Plan may not be less than 100% of the fair market value of our common stock on the option grant date. Optionees may pay the exercise price by using:

	·	cash;
	·	shares of our common stock that the Optionee already owns;
	·	an immediate sale of the option shares through a broker approved by us; or
	·	any other form of payment as the compensation committee determines.

 

Restricted Shares. In general, these awards will be subject to vesting. Vesting may be based on length of service, the attainment of performance-based milestones, or a combination of both, as determined by the plan administrator.

 

Amendments or Termination. Our board of directors may amend or terminate the 2005 Incentive Compensation Plan at any time. If our board of directors amends the plan, it does not need to ask for stockholder approval of the amendment unless required by applicable law.

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ITEM 7.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Related Party Transactions

During 2007, the Company sold 100,000 shares of the Company’s common stock, at a per share price of $0.75 per share to Glenn Biggs. At the time of these sales, Mr. Biggs was a member of the Company’s board of directors. The aggregate proceeds received from this sale was $75,000. As an incentive to invest, Mr. Biggs was granted 18,750 warrants to purchase shares of common stock at $0.75 per share. The fair value of these warrants using the Black-Scholes option pricing model totaled $5,475. These issuances were made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933. The terms of these transactions were on terms that would have been made between unaffiliated third parties.

 

In October 2007, the Company and the holders of the wellbore interests in the South Belridge Field (the “Holders”), entered into an agreement pursuant to which the Holders assigned their ownership interest in the wellbores back to the Company in consideration for promissory notes in the aggregate principal amount of $3,000,000 and an aggregate of 373,333 shares of the Company’s common stock. The notes bear interest at 9% per annum and mature in October 2009. In addition, the Company issued the Holders five year warrants exercisable for up to 1,000,000 shares of the Company’s common stock at a per share exercise price of $0.75. One of the Company’s directors, Mr. Pensack and members of his immediate family participated in this transaction and received promissory notes in the aggregate principal amount of $1,250,000, 209,999 shares of the Company’s common stock and warrants exercisable for up to 562,500 shares of the Company’s common stock at $0.75 per share.  Mr. Pensack and members of his immediate family earned interest of $28,571 and no payments were made during 2007. Their principal balance of $1,250,000 was still outstanding at December 31, 2007 . The terms of the transaction were on terms that would have been made between unaffiliated third parties.

During 2007, the Company entered into notes payable totaling $120,000 with one officer and four directors. These notes bear interest at a fixed rate of 9% and are unsecured. Upon maturity and in lieu of receipt of payment of all or a portion of the outstanding principal and interest, the note holder may convert their note, in whole or in part, into shares of the Company’s common stock determined by dividing the principal amount of the note and interest by $0.75 per share. The Company accrue $2,868 of interest on these notes in 2007 and made no principal or  interest payments during 2007. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

During 2007, the Company entered into convertible notes payable of $1,200,000 with an individual director, Harvey Pensack. These notes are unsecured and non-interest bearing, but were issued at a 20% discount. These notes mature in one year from the note date and are convertible into shares of common stock at an exchange rate of $0.75 per share. No principal payments were made during 2007 and total outstanding balance at December 31, 2007 was $747,819 net of debt discount of $452,181. The terms of these transactions were on terms that would have been made between unaffiliated third parties.

During 2007, the Company executed notes payable with three officers of the Company; $87,333 from Dan Williams, $87,333 from Robert Sepos, and $87,667 from Dominick Maggio. Proceeds were used to fund certain operating cost of the Company. Repayments of $84,999 to Dan Williams, $70,666 to Robert Sepos, and $85,001 to Dominick Maggio were made during 2007. Mr. Maggio’s remaining balance of $2,666 was offset against an outstanding receivable balance. At December 31, 2007, the Company had outstanding note payable balances to Mr. Williams and Mr. Sepos of $2,334 and $16,667, respectively. These notes were unsecured, did not bear interest and had a term of three months. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

During 2007, the Company had a related party $700,000 convertible note with Louis Fusz, the father of director Eugene Fusz, which matured and was extended. As consideration for extending the terms of this note, the Company granted 933,333 warrants with an exercise price of $0.75 per share. These warrants expire five years from the date of grant. The fair value of these warrants using the Black-Scholes option pricing model totaled $255,266. Interest expense on this note was $97,797 for 2007 and the Company made cash payments for accrued interest of $106,081 during 2007. The Company is currently in default on this note payable. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

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During 2007, the Company entered into a three month unsecured convertible note bearing interest at 9% with one of the Company’s directors, Mr. Pensack. During 2007, Mr. Pensack  converted $200,000 of principal and $2,126 of accrued interest into 269,501 shares of the Company’s common stock at an exchange rate of one share for each $0.75 of principal and interest. As an incentive to convert, Mr. Pensack was granted 50,000 warrants to purchase shares of common stock at $0.75 per share, expiring in five years from date of grant. The fair value of these warrants using the Black-Scholes option pricing model totaled $14,600. These issuances were made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

At December 31, 2007, the Company had a total payable of $248,412 due to directors, officers and employees. At December 31, 2007 the Company had receivables of $51,154 due from directors, officers and employees. These amounts are recorded in other accounts payable and other accounts receivable, respectively. The terms of these transactions were on terms that would have been made between unaffiliated third parties.

During 2007, the Company sold to an individual director, Mr. Harvey Pensack a 1% ORRI in the Days Creek oil and natural gas property and granted to him 30,000 warrants with an exercise price of $0.75 per share, generating total proceeds of $100,000. This issuances was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

During 2007, the Company granted to an individual director, Dr. John Ritota, 2,000,000 warrants to purchase common stock at $0.75 per share, for fund raising services. The fair value of these warrants using the Black-Scholes option pricing model totaled $606,000. This issuances was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

In 2007, the Company paid a total of $2,100 to an individual director, Dr. John Ritota for the rental of office space in Florida owned by Dr. Ritota. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

In 2007, the Company granted 1,200,000 stock options to members of its board of directors whose value, as assessed using the Black-Scholes method, was $371,100, for their service as directors. Additionally, stock based compensation of $100,800 was recorded in 2007, related to the vesting of 400,000 options granted to advisory directors in prior years. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

In 2007, the Company paid a total of $177,145 to officers or their immediate family for consulting services performed while they were not an employee of the Company. The terms of these transactions were on terms that would have been made between unaffiliated third parties.

During 2006, the Company sold 466,667 shares of the Company’s common stock, at a per share price of $0.75 per share to Harvey Pensack or members of their immediate families. At the time of the sale, Messrs, Pensack was a member of the Company’s board of directors. The aggregate proceeds received from these sales were $350,000. The terms of this transaction were on terms that would have been made between unaffiliated third parties.

In 2006, the Company offered all existing warrant holders the right to exchange their warrants on a four-for-five-cashless-exchange basis. The Company issued a total of 15,165,600 shares of common stock to related party warrant holders in exchange for 18,957,000 warrants with an original exercise price of $0.75 per share. Warrant holders to whom the Company granted this right included Stephen Warner, Harvey Pensack, Eugene Fusz, Marvin Watson, and members of their immediate families. At the time of the transaction, Messrs Warner, Pensack, Fusz and Watson were members of the Company’s board of directors. Of the shares issued to related parties, an aggregate of 11,006,135 shares of common stock were issued to these board of directors and members of their immediate families. The fair market value of the underlying common stock on the date of the exercise was $0.75 per share. The Company recorded approximately $9,200,000 as other expense to account for the fair value of the cashless exchange by all related parties during 2006. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

In 2006, the Company issued promissory notes in the aggregate principal amount of $3,969,472 to related parties, including a $3,650,000 promissory note to Carl Landers discussed below. These notes bore interest at 9% per annum. Total interest expense on all related party notes was $255,978 for 2006. In connection with the issuance of these notes, the Company issued warrants to these related parties to purchase 375,000 shares of the Company’s common stock at an exercise price of $0.75 per share. In addition, certain related party note holders are entitled either to receive a net revenue interest in certain of the Company’s oil and natural gas properties or to enter into revenue sharing agreements with the Company. Of these notes, principle payments of $124,805 and interest payments of $133,693 were paid to the note holders and principle and interest of $266,667 and $7,363, respectively, was converted to equity by the note holder. For the promissory notes issued in 2006, $3,578,000 remained outstanding at December 31, 2007. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

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In 2006, the Company and Mr. Robert McCann, a former member of the board of directors, entered into a settlement agreement and release pursuant to which the Company paid Mr. McCann $318,000 for all consulting services performed by Mr. McCann and Mr. McCann released the Company from all claims in connection therewith.

In 2006, the Company granted 1,575,000 stock options to members of its board of directors and advisors whose value, as assessed using the Black-Scholes method, was $923,100, for their service as directors and advisors.

In 2006, the Company paid a total of $4,900 to Dr. John Ritota for the rental of office space in Florida owned by Dr. Ritota. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

In 2006, the Company paid a total of $37,000 to officers or their immediate family for consulting services performed while they were not an employee of the Company. The terms of these transactions were on terms that would have been made between unaffiliated third parties.

In 2006, the Company finalized a purchase and sale agreement with Carl Landers, a member of the board of directors, to purchase three patents related to the Company’s lateral drilling technology. The Company advanced Mr. Landers $100,000 in 2005 while negotiating the terms of the purchase. Pursuant to the finalized agreement, the Company paid Mr. Landers an additional $250,000 in cash and agreed to issue Mr. Landers a note payable of $3,650,000 and 1,000,000 shares of the Company’s common stock valued at $0.75 per share. Interest on this note began to accrue on January 1, 2007 and $132,000 was recorded as interest expense in 2007. Cash interest payments of $132,000 on this note were made during 2007. The terms of the transaction were on terms that would have been made between unaffiliated third parties.

In addition to the transactions described above, the Company entered into various Revenue Sharing Agreements with several of its Board of Directors and members of their immediate family prior to 2006. The following table summarizes outstanding Revenue Sharing Agreements and amounts earned under those agreements during 2007 and 2006.

 

Plan		Interest			2007			2006
$4M Net Distribution (1)
Pensack Maxim Trust dtd 12/14/2005 (controlled by director Harvey Pensack)			6.50	%	$	8,298		$	10,482
Stephen J. Warner, director			13.50	%		17,235			21,768
Theodore C. Ritota (brother of director, John Ritota)			3.00	%		3,830			4,838
John Ritota, director			5.00	%		6,383			8,063
SB & Belton Field RSA (2)
Harvey Pensack, director			5.93	%		19,121			30,563
Bioform (controlled by director Stephen J. Warner)			8.71	%		28,085			44,892
Marion Field RSA (4)
Louis Fusz (father of director Eugene Fusz)			1.20	%		–			845
Total					$	82,952		$	121,451

(1)	$4M Net Distribution provides participants a percentage of the first $4,000,000 per year of the Company’s net operating revenue. The net operating revenue subject to the net revenue sharing arrangement declines by 2.5% per annum beginning January 1, 2008 and terminates in 40 years.
(2)	SB & Belton Field RSA provides participants a net profits interest in the Company’s South Belridge Field and the original 3,008 acre lease of the Company’s Belton Field.
(3)	SB 7 Well Program provides participants a net profits interest in seven certain wells of the Company’s South Belridge Field.
(4)	Marion Field RSA provides participants a net profits interest in the Company’s Marion Field.

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ITEM 8.

LEGAL PROCEEDINGS

 

The Company is subject to litigation and claims that have arisen in the ordinary course of business. Management believes, individually or in aggregate, such litigation and claims will not have a material adverse impact on our financial position or our results of operations but these matters are subject to inherent uncertainties and management's view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position and the results of operations for the period in which the effect becomes reasonably estimable. We accrue for such items when a liability is both probable and the amount can be reasonably estimated.

The following describes legal action being pursued against the Company outside the ordinary course of business.

In the suit, Raymond Thomas, et al. vs. Ashley Investment Company, et al., in the 5th Judicial District Court for Richmond Parish, Louisiana, numerous present and former owners of property are seeking damages in an unspecified amount for alleged soil, groundwater and other contamination, allegedly resulting from oil and gas operations of multiple companies in the Delhi Field in Richmond Parish, Louisiana over a time period exceeding fifty years. Originally consisting of 14,000 acres upon discovery of the field in 1952, the Company acquired an interest in leases covering 1,400 acres in 2006. Although the suit was filed in 2005, and was pending when the Company acquired its interest in 2006, as part of the acquisition terms, the Company agreed to indemnify predecessors in title, including its grantor, against ultimate damages related to the prior operations. As part of the Company’s purchase terms, a Site Specific Trust Account was established with the State of Louisiana Department of Natural Resources intended to provide funds for remediation of the lands involved in its acquired interest. Principal defendants in the suit, in addition to the Company, include the Company’s indemnities including McGowan Working Partners, MWP North La, LLC., Murphy Exploration & Production Company, Ashley Investment Company, Eland Energy, Inc. and Delhi Package I, Ltd. Discovery activity in the suit has only recently begun, and it is too early to predict the ultimate outcome, although the Company believes that it has meritorious defenses with regard to the plaintiffs’ claims and, thus, with regard to the extent of its monetary exposure under its indemnity obligation. The Company intends to defend the suit vigorously. At December 31, 2007, the Raymond Thomas, et al v. Ashley Investment Company, et al litigation was still in the preliminary stages of discovery and the plaintiffs’ experts had not yet provided their reports which are necessary to add clarity to the nature and extent of the claims being made by the plaintiffs in the matter.  As such, we believe that a loss was neither probable nor estimable as of May 31, 2008.

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ITEM 9.  MARKET PRICE OF  AND DIVIDENDS ON THE COMPANY’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

 

General

 

Our common stock is not registered with the Securities and Exchange Commission. Our common stock is not publicly traded and there is not an established active public market for our common stock. No assurance can be given that an active market will exist for our common stock.

 

We are filing this Registration Statement on Form 10 for the purpose of enabling our common stock to commence trading on the National Association of Securities Dealers, Inc. (“NASD”) OTC Bulletin Board. This Registration Statement on Form 10 must be declared effective by the SEC prior to our being approved for trading on the NASD OTC Bulletin Board. Our market makers must make an application to the NASD following the effective date of this Registration Statement on Form 10 in order to have our common stock quoted on the NASD OTC Bulletin Board.

 

Holders

 

As of May 31, 2008, there were 125,474,313 shares of our common stock outstanding, held by 669 shareholders of record.

 

Pursuant to Rule 144 of the Securities Act, a number of the common shares will be eligible for sale upon the listing of the Company as those shares have been held for more than two years, and a percentage have been held past one year pursuant to rule 144(k) and Rule 144.

Equity Compensation Plan Information

 

We currently maintain a 2005 Incentive Compensation Plan under which shares of our common stock are authorized for issuance to employees and non-employees. Our 2005 Incentive Compensation Plan has been approved by our shareholders. The following table sets forth all compensation plans previously approved by the Company’s security holders and all compensation plans not previously approved by the Company’s security holders as of December 31, 2007:

Plan Category		Number of securities to be issued upon exercise of outstanding options, warrants and rights			Weighted average exercise price of outstanding options, warrants and rights			Number of securities Remaining available for future issuances under equity compensation plans
All compensation plans previously approved by security holders			30,000,000		$	0.75			19,250,000
All compensation plans not previously approved by security holders			–		$	–			–
Total			30,000,000		$	0.75			19,250,000

 

Dividends

 

Holders of Common Stock are entitled to receive dividends, when, as, and if declared by the Board of Directors out of funds legally available. We have not declared any dividends on our common stock. The Board of Directors presently intends to follow a policy of retaining the Company earnings, if any, to finance our future growth, including possible acquisitions, thus it is unlikely that dividends will be declared in the near future.

ITEM 10.

RECENT SALES OF UNREGISTERED SECURITIES

 

Notes Payable

During 2007, the Company executed notes payable with three officers of the Company totaling $262,333. Proceeds were used to fund certain operating cost of the Company. During 2007, $240,666 was repaid and $2,666 was offset against a receivable, leaving a remaining balance of $19,001. These notes were unsecured, did not bear interest and had a term of three months. These issuances were made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

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During 2007, the Company offered various note holders the option to convert their outstanding notes payable and corresponding accrued interest into the Company’s common stock at an exchange rate of one share for each $0.75 of principal and interest. These notes were originally not convertible in accordance with the underlying terms of the loan agreements. During 2007, note holders converted $50,000 of principal and $6,912 of accrued interest into 75,883 shares, of the Company’s common stock. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2006, the Company executed unsecured notes payable with various individual investors aggregating $2,569,472. Of the notes payable executed during 2006, $319,472 were entered into with related parties. These notes payable mature from April 25, 2006 to May 18, 2007 bearing interest at fixed rates ranging from 6% to 12%. Simple interest will accrue from the note issue date and be due and payable either at maturity or quarterly or semi-annually until maturity. Should a note payable go into default, interest will accrue at a higher rate. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2006, the Company offered various note holders the option to convert their outstanding notes payable and corresponding accrued interest into the Company’s common stock at an exchange rate of one share for each $0.75 of principal and interest. These notes were originally not convertible in accordance with the underlying terms of the loan agreements. As a result, various note holders converted $2,216,667 of principal and $15,993 of accrued interest into 2,976,879 shares of the Company’s common stock. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

Convertible Debt

At December 31, 2007, the Company had convertible notes payable totaling $48,428,772, of which $3,270,000, was with related parties. Out of total outstanding notes payable at December 31, 2007, $700,000 originally matured on March 29, 2007, but was extended to mature on March 30, 2008. The Company is currently in default on certain of these notes payable and is in the process of repaying these amounts as cash flows permit. At December 31, 2007, should the note holders execute their right to convert, the Company would be obligated to issue 60,571,696 shares of the Company’s common stock.

 

During 2007, the Company entered into unsecured notes payable totaling $4,520,000. These notes bear interest at a fixed rate of 9% and are unsecured. Simple interest will accrue from the note date and is due and payable either at maturity or semi annually until maturity. Should the convertible note go into default, interest will accrue at a rate of 18%. Upon maturity and in lieu of receipt of payment of all or a portion of the outstanding principal and interest, the note holder may convert their note, in whole or in part, into shares of the company’s common stock determined by dividing the principal amount of the note and interest by $0.75 per share. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2007, note holders converted $200,000 of principal and $2,126 of accrued interest into 269,501 shares of the Company’s common stock. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2006, the Company executed three convertible promissory notes with Maxim TEP, PLC, a U.K. based unaffiliated company, totaling $37,408,772, of which $20,000,000 matured on June 30, 2007, bearing interest at the rate of zero percent through December 31, 2006, and 8% from January 1 through the maturity date. The remaining $17,408,772 is comprised of two notes, $15,408,772 and $2,000,000, which matured on January 31, 2007 and August 11, 2007, respectively, and bear interest at 8% per annum. These three notes provide for default interest rates from 10% to 18%. These notes payable are convertible into shares of the Company’s common stock at an exchange rate of $0.75 per share, or into approximately 49.9 million shares. These notes are secured by certain oil and natural gas properties of the Company. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During November 2006, the Company entered into three convertible notes payable totaling $2,000,000 each ($6,000,000 in total) bearing interest at a rate of 10% which matured on October 31, 2007, secured by the leases in the Days Creek Field. These three notes provide for default interest rates of 15%. These notes payable were originally convertible into shares of the Company’s common stock at an exchange rate of $1.50 per share, or into approximately 4,000,000 shares of common stock. These notes are collateralized by the Company’s oil and natural gas properties in Days Creek. During 2007, the maturity dates on these notes were extended to mature on February 1, 2008, whereby the Company agreed to pay an additional $300,000 to the note holders as a fee for the extension. In February 2008, these notes were extended again to mature on April 30, 2008 for an additional extension fee of $300,000 and the exchange rate of $1.50 per share was amended to $0.75 per share, resulting in the $6,000,000 in convertible notes being convertible into 8,000,000 shares of common stock. The extension fee is being amortized to interest expense using the interest method over the extension period. The Company has an executed debt facility term sheet and is in the later stages of the due diligence process with an institutional financial company for development, refinancing and acquisition funding, of which a portion of the proceeds are for the payment of the three notes payable totaling $6,000,000. The notes have been verbally extended to the date this funding goes forward and the proceeds are released, but in lieu of an executed agreement they are technically in default. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

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During 2006, several note holders converted $301,125 of principal of their notes and $21,762 of corresponding accrued interest into 430,519 and of the Company’s common stock at an exchange rate of one share for each $0.75 of principal and interest converted. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

Revenue Sharing Agreements

From time to time a Revenue Sharing Agreement (“RSA”) may be granted by the Company out of their existing working interest in oil and natural gas properties. These RSAs are calculated as a percentage of the Company’s interest in an oil or natural gas property after lease operating expenses.   The Company has issued the following RSAs since its inception:

	1)	$4M Net Distribution Plan - 37% net revenue interest in all wells in which the Company shall have an interest, not to exceed $4,000,000 per year of the Company’s net operating revenue, as defined. The net operating revenue subject to the net revenue sharing arrangement declines by 2.5% per annum beginning January 1, 2008 and terminates in 40 years;
	2)	SB & Belton Field RSA - a 20% net revenue interest in field net revenues, as defined, generated from the Company’s oil and gas properties in the South Belridge Field and the original 3,008 acre lease of the Company’s Belton Field;
	3)	SB 7 Well Program - an approximate aggregate 4.78% net revenue interest in seven wells owned by the Company in South Belridge, California, and;
	4)	Marion Field RSA - an aggregate 1.4% net profits interest in the Company’s Marion Field.

Preferred Stock

As of May 31, 2007, the Company converted $2,000,000 of certain convertible notes arising from the re-purchase of working interest in wellbores in the South Belridge Field, to Series A Preferred Stock, $.00001 par value per share, at a price of $0.55 per share for each dollar of principal. The Company is in negotiations to convert the remaining $1,000,000 of these wellbore re-purchase convertible notes and accrued interest into preferred stock. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

Common Stock Offering

During 2007, total proceeds of $3,141,349 were generated through private offerings of 4,188,465 shares of common stock at $0.75 per share. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

During 2007, total proceeds of $244,000 were generated through private offerings of 325,334 shares held in treasury at $0.75 per share. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2007, the Company issued 2,500,000 shares of common stock with a fair value of $0.75 per share for a total of $1,875,000 to officers and employees for their employment services and is recorded as stock based compensation. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2007, the Company issued 1,050,753 shares of common stock with a fair value of $0.75 per share for a total of $788,065 to officers and employees to settle accrued payroll amounts. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2007, note holders comprising $250,000 of principal elected to convert into 333,333 shares of the Company’s common stock at an exchange rate of one share for each $0.75 of principal. In addition, these note holders elected to convert the corresponding accrued interest of $9,038 into 12,051 shares of the Company’s common stock at an exchange rate of one share for each $0.75 of accrued interest. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2007, the Company issued 373,333 shares of common stock at a fair value of $0.75 per share, in conjunction with the purchase of certain ownership interests in four well bores in South Belridge Field. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

During 2006, total proceeds of $5,050,650 were generated through private offerings of common stock from the issuance of 6,760,865 at $0.75 per share. Of the total number of common shares sold during the year ended December 31, 2006, 466,667 were sold to related parties generating proceeds of $350,000. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

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During 2006, the Company issued 2,011,500 shares of common stock with a fair value of $0.75 per share totaling $1,508,625 for services to third parties. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2006, as a result of late payments to Orchard, the Company issued 1,333,333 shares of common stock as late fees. The fair market value of the underlying common stock on the date of issuance was $0.75 per share. The Company recorded $1,000,000 as penalties for late payments to operator to account for the fair value of the common stock issued. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2006, the Company granted 1,000,000 shares of common stock at a fair value of $0.75 per share, or $750,000, as partial consideration to a related party for the purchase of patents, technology, techniques and trade secrets embodied in the LHD Technology. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2006, the Company offered warrant holders an option to exchange their warrants on a four for five cashless exchange basis. The Company issued 18,305,545 shares of common stock to warrant holders and cancelled approximately 22,915,255 warrants, with an original exercise price of $0.75 per share. The fair market value of the underlying common stock on the date of the exchange was $0.75 per share and the Company recorded warrant inducement expense of $10,934,480. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2006, note holders comprising $2,555,547 of principal and accrued interest elected to convert into 3,407,398 shares of the Company’s common stock, respectively, at an exchange rate of one share for each $0.75 of principal. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2006, the Company repurchased 333,333 of the Company’s common stock for a total cost of $250,000. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

Stock Warrants

During 2007, the Company issued 4,255,133 shares of common stock and received cash proceeds of $3,191,350. As an incentive to invest, 2,300,877 warrants to acquire shares of common stock of the Company with an exercise price of $0.75 per share were granted to these investors. Additionally, 2,056,010 warrants were granted to related and unrelated third parties for common stock fund raising services. These warrants all expire five years from their date of grant. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2007, the Company entered into various note payable agreements with related party investors to fund its operations. These note payable agreements provided for warrants to purchase a total of 470,000 of the Company’s common stock, at an exercise price of $0.75 per share. These warrants expire three or five years from the date of grant. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

During 2007, the Company had certain unrelated and related party notes that matured and were extended. As consideration for extending the terms of these notes, the Company granted 1,411,331 warrants (933,332 was attributable to related parties) with an exercise price of $0.75 per share. These warrants expire five years from the date of grant. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

During 2007, certain unrelated and related party notes were converted to common stock of the Company of which 87,562 warrants (50,000 was attributable to related parties) were granted as an incentive to convert the notes into common stock with an exercise price of $0.75 per share. These warrants expire five years from the date of grant. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

In contemplation of divesting the South Belridge Field, effective October 1, 2007, the Company repurchased various working interests in four well bores in its South Belridge Field that it had sold to four individuals in 2005. The purchase price consideration included the granting of 1,000,000 warrants with an exercise price of $0.75 per share. Of the total warrants issued 562,500 warrants, were issued to related parties. These warrants expire three years from the date of grant. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

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Also, in contemplation of divesting the South Belridge Field, effective October 1, 2007, the Company reacquired certain Revenue Sharing Agreements comprising 4.36% in the aggregate on a certain seven wells located in the South Belridge Field by granting 1,016,672 warrants with an exercise price of $0.75 per share. These warrants expire three years from the date of grant. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

During 2007, the Company sold a 5% ORRI in oil and natural gas properties located in the Days Creek Field for $500,000. The ORRI sales agreements also provided for warrants to purchase a total of 150,000 shares of the Company’s common stock with an exercise price of $0.75 per share expiring three years from the date of the agreements. Of these warrants issued, 30,000 were issued to related parties. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

During 2006, warrants to acquire 562,163 shares, of the Company’s common stock with an exercise price of $0.75 per share were granted to various stockholders in connection with the sale of the Company’s common stock. These warrants expire five years from the date of grant. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2006, warrants to purchase 1,288,815 shares of the Company’s common stock with an exercise price of $0.75 per share were granted to certain consultants, Board of Directors, and Advisory Directors for consulting and fund raising services. These warrants expire five years from the date of grant. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2006, the Company entered into various note payable agreements with related and unrelated third party investors to fund its operations. At December 31, 2006, certain note payable agreements provide for warrants to purchase a total of 825,000 of the Company’s common stock, at an exercise price of $0.75 per share of which 375,000 shares were granted to related parties. These warrants expire three or five years from the date of grant. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

Stock Options

During 2007, the Company granted options to purchase 1,200,000 shares of the Company’s common stock at an exercise price of $0.75 per share to Board of Directors and Advisory Directors for services provided. These options expire five or ten years from the date of grant. All the options granted in 2007 vested immediately. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2007, the Company granted options to purchase 650,000 shares of the Company’s common stock at an exercise price of $0.75 per share to employees for services provided. These options expire five years from the date of grant. The options vested immediately upon grant or within 90 days from the date of grant. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2006, the Company granted options to purchase 1,575,000 shares of the Company’s common stock at an exercise price of $0.75 per share to the Board of Directors and Advisory Directors for services provided. These options expire ten years from the date of grant. All the options granted in 2006 vested immediately on the grant date. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2006, the Company entered into a Separation Agreement with a board member. As part of the agreement, at the board member’s option, at any time prior to March 31, 2007, the board member may elect to exchange their options to purchase 150,000 shares of the Company’s stock and receive 250,000 shares of the Company’s stock with no exercise price. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

 

During 2006, the Company granted options to purchase 650,000 and shares of the Company’s common stock at an exercise price of $0.75 per share to employees for services provided, these options expire five to seven years from the date of grant. Of these options granted, 525,000 were 100% vested on the date of grant during 2006 and 125,000 granted in 2006 vest one year from the grant date. This issuance was made in reliance upon an exemption from the registration requirements of Section 5 provided by Section 4(2) of the Securities Act of 1933.

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ITEM 11.

DESCRIPTION OF THE COMPANY’S SECURITIES

General

 

The following is a summary of our capital stock and certain provisions of our articles of incorporation and bylaws, as they are currently in effect. This summary does not purport to be complete and is qualified in its entirety by the provisions of our articles incorporation and bylaws, copies of which have been filed as exhibits to this Registration Statement on Form 10.

 

The Company’s authorized capital stock consists of 250,000,000 shares of common stock, $0.00001 par value per share (the “Common Stock”), and 50,000,000 shares of preferred stock, $0.00001 par value per share (the “Preferred Stock”).

 

Common Stock

 

As of December 31, 2007, there were 85,604,516 shares issued and 85,579,516 shares outstanding of common stock.

 

The holders of common stock are entitled to one vote per share on all matters to be voted upon by the shareholders. The holders of common stock are entitled to receive ratably such dividends, if any, as may be declared from time to time by the board of directors out of funds legally available, subject to preferences that may be applicable to preferred stock, if any, then outstanding. See “ Dividends” under Item 9. In the event of a liquidation, dissolution or winding up of our Company, the holders of common stock are entitled to share ratably in all assets remaining after payment of liabilities, subject to prior distribution rights of preferred stock, if any, then outstanding. The common stock has no preemptive or conversion rights or other subscription rights. There are no redemption or sinking fund provisions applicable to the common stock. All outstanding shares of common stock are fully paid and non-assessable.

 

Preferred Stock

 

The Board of Directors has the authority, without further action by the shareholders, to issue up to 50,000,000 shares of preferred stock, $0.00001 par value per share, in one or more series and to fix the rights, preferences, privileges and restrictions thereof, including dividend rights, conversion rights, voting rights, terms of redemption, liquidation preferences, sinking fund terms and the number of shares constituting any series or the designation of such series, without any further vote or action by shareholders. The issuance of Preferred Stock could, if and when issued, adversely affect the voting power of holders of Common Stock and the likelihood that such holders will receive dividend payments and payments upon liquidation and could have the effect of delaying, deferring or preventing a change in control of the Company.

As of December 31, 2007, there were no shares of Preferred Stock issued and outstanding.

As of March 31, 2008, the Board of Directors resolved to cancel the Company’s previous class of preferred stock and issue up to 50,000,000 shares of a new class of preferred stock, a Series A Preferred Stock, $.00001 par value per share. This series has liquidation preference above common stock. The holders of Series A Preferred Stock shall be entitled to receive dividends if and when declared by the Board of Directors. Each share of Series A Preferred Stock shall have voting rights identical to a share of Common Stock (i.e. one vote per share) and shall be permitted to vote on all matters on which holders of Common Stock are entitled to vote. So long as any shares of Series A Preferred Stock remain outstanding, the Corporation shall not without first obtaining the approval of the holders of seventy-five percent (75%) of the then-outstanding shares of Series A Preferred Stock: (i) alter or change the rights, preferences or privileges of the shares of Series A Preferred Stock so as to adversely affect such shares; (ii) increase or decrease the total number of authorized shares of Series A Preferred Stock; (iii) issue any Senior Securities; or (iv) take any action that alters or amends this Series.

  Warrants and Options

 

As of December 31, 2007, there were outstanding warrants to purchase up to 14,089,946 shares of common stock at an exercise price of $0.75 per share. As of December 31, 2007, there were outstanding options to purchase up to 10,350,000 shares of common stock all at an exercise price of $0.75 per share.

Convertible Promissory Notes

 

As of December 31, 2007, there were outstanding convertible promissory notes in the aggregate principal amount of $48,428,772 which bear interest ranging from 8% to 18% per annum. Outstanding principal is convertible at any time at the option of the holder into shares of the Company’s common stock at conversion rates of $0.75 to $1.50 per share. The $6,000,000 of convertible debt with an exchange rate of $1.50 per share was subsequently amended to an exchange rate of $0.75 per share.

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The following table summarizes the Company’s outstanding convertible promissory notes at December 31, 2007.

Name		Interest %			Default Interest %			Maturity Date			Collateral			Amount			Exercise Price			No. of Common Shares Issuable Upon Possible Conversion as of December 31, 2007
Louis Fusz, Sr.			12.0	%		18.0	%		03/29/08			Unsecured		$	700,000		$	0.75			933,333
Oil Man Rig, LLC			10.0	%		15.0	%		02/01/08			Property(1)			2,000,000		$	1.50			1,333,333
Bass Pro, LLC			10.0	%		15.0	%		02/01/08			Property(1)			2,000,000		$	1.50			1,333,333
Richard Williamson Operating Co., Inc.			10.0	%		15.0	%		02/01/08			Property(1)			2,000,000		$	1.50			1,333,333
Maxim TEP, PLC (GEF)			8.0	%		10.0	%		06/30/07			Property(2)			20,000,000		$	0.75			26,666,667
Maxim TEP, PLC (GEF)			8.0	%		18.0	%		01/31/07			Property(2)			15,408,772		$	0.75			20,545,029
Maxim TEP, PLC (GEF)			8.0	%		10.0	%		08/11/07			Property(2)			2,000,000		$	0.75			2,666,667
Harvey Pensack(3)			20.0	%		–			10/02/08			Unsecured			600,000		$	0.75			800,000
Harvey Pensack(3)			20.0	%		–			10/31/08			Unsecured			600,000		$	0.75			800,000
Wellbore Note Holders			9.0	%		18.0	%		10/03/09			Unsecured			3,000,000		$	0.75			4,000,000
Officers			9.0	%		9.0	%		11/13/07			Unsecured			10,000		$	0.75			13,333
Directors			9.0	%		9.0	%		11/13/07			Unsecured			110,000		$	0.75			146,667
														$	48,428,772						60,571,695

 

	(1)	Notes are collateralized by leases in the Days Creek Field.
	(2)	Notes are collateralized by the South Belridge Field.
	(3)	Notes are non-interest bearing, but were issued at a 20% discount.

 

Interest paid on the Louis Fusz note for the year ended December 31, 2007 is $106,081 and interest paid to Oil Man Rig, LLC and Bass Pro, LLC for the year ended December 31, 2007 is $600,000. Interest accrued for the remaining convertible notes for the year ended December 31, 2007 is $4,705,897. The annual effective interest rates for each of the respective moths during 2007 and the total principal and interest accrued at December 31, 2007 specifically on Maxim TEP, PLC convertible notes is as follows:

 

		2007
		Jan			Feb			Mar			Apr			May			Jun			Jul			Aug			Sep			Oct			Nov			Dec
Maxim TEP, PLC
Tranches 1&3
$22,000,000
Effective Rate			8	%		10	%		10	%		10	%		10	%		10	%		10	%		10	%		10	%		10	%		10	%		10	%
Tranche 2
$15,408,772
Effective Rate			8	%		10	%		12	%		14	%		16	%		18	%		18	%		18	%		18	%		18	%		18	%		18	%

			Total Principal Outstanding		$	37,408,772
			Total Interest Outstanding		$	4,556,337

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Anti-Takeover Effects of Our Charter and Bylaws and Texas Law

 

Some provisions of Texas law and our articles of incorporation and bylaws could make the following transactions more difficult:

 

	·	acquisition of our Company by means of a tender offer, a proxy contest or otherwise; and
	·	removal of our incumbent officers and directors.

 

These provisions, summarized below, are expected to discourage and prevent coercive takeover practices and inadequate takeover bids. These provisions are designed to encourage persons seeking to acquire control of our Company to first negotiate with our board of directors. They are also intended to provide our management with the flexibility to enhance the likelihood of continuity and stability if our board of directors determines that a takeover is not in the best interests of our shareholders. These provisions, however, could have the effect of discouraging attempts to acquire us, which could deprive our shareholders of opportunities to sell their shares of common stock at prices higher than prevailing market prices.

 

Election and Removal of Directors . Our bylaws contain provisions that establish specific procedures for appointing and removing members of the board of directors. Our bylaws provide that vacancies and newly created directorships on the board of directors may be filled only by a majority of the directors then serving on the board (except as otherwise required by law or by resolution of the board).

Special Shareholder Meetings . Under our bylaws, only our President, our board of directors and holders of not less than 1/10 ^th of all the shares issued, outstanding and entitled to vote may call special meetings of shareholders.

 

Texas Anti-Takeover Law . Following this registration, we will be subject to Article 21 of the Texas Business Organizations Code, which is an anti-takeover law. In general, Article 21 prohibits a publicly held Texas corporation from engaging in a business combination with an interested shareholder for a period of three years following the date that the person became an interested shareholder, unless the business combination or the transaction in which the person became an interested shareholder is approved in a prescribed manner. Generally, a business combination includes a merger, asset or stock sale, or another transaction resulting in a financial benefit to the interested shareholder. Generally, an interested shareholder is a person who, together with affiliates and associates, owns 15% or more of the corporation’s voting stock or holders of at least two-thirds of the shares of common stock entitled to vote held by disinterested directors. The existence of this provision may have an anti-takeover effect with respect to transactions that are not approved in advance by our board of directors, including discouraging attempts that might result in a premium over the market price for the shares of common stock held by shareholders.

No Cumulative Voting . Under Texas law, cumulative voting for the election of directors is not permitted unless a corporation’s articles of incorporation authorize cumulative voting. Our articles of incorporation and bylaws do not provide for cumulative voting in the election of directors. Cumulative voting allows a minority shareholder to vote a portion or all of its shares for one or more candidates for seats on the board of directors. Without cumulative voting, a minority shareholder will not be able to gain as many seats on our board of directors based on the number of shares of our stock the shareholder holds as the shareholder would be able to gain if cumulative voting were permitted. The absence of cumulative voting makes it more difficult for a minority shareholder to gain a seat on our board of directors to influence our board’s decision regarding a takeover.

 

Undesignated Preferred Stock . The authorization of undesignated preferred stock makes it possible for our board of directors to issue preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of our Company.

These and other provisions could have the effect of discouraging others from attempting hostile takeovers and, as a consequence, they may also inhibit temporary fluctuations in the market price of our common stock that often result from actual or rumored hostile takeover attempts. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish transactions that shareholders may otherwise deem to be in their best interests.

 

Transfer Agent and Registrar

 

The transfer agent and registrar for our common stock is First American Stock Transfer (FAST) located at 706 East Bell Road, Suite 202, Phoenix, AZ 85022. Their telephone number is (602) 485-1346.

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ITEM 12.

INDEMNIFICATION OF DIRECTORS AND OFFICERS

 

Article 2.02-1 of the Texas Business Corporation Act provides for the indemnification of officers, directors, employees, and agents. A corporation shall have power to indemnify any person who was or is a party to any proceeding (other than an action by, or in the right of, the corporation), by reason of the fact that he or she is or was a director, officer, employee, or agent of the corporation or is or was serving at the request of the corporation as a director, officer, employee, or agent of another corporation, partnership, joint venture, trust, or other enterprise against liability incurred in connection with such proceeding, including any appeal thereof, if he or she acted in good faith and in a manner he or she reasonably believed to be in, or not opposed to, the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe his or her conduct was unlawful. The termination of any proceeding by judgment, order, settlement, or conviction or upon a plea of nolo contendere or its equivalent shall not, of itself, create a presumption that the person did not act in good faith and in a manner which he or she reasonably believed to be in, or not opposed to, the best interests of the corporation or, with respect to any criminal action or proceeding, had reasonable cause to believe that his or her conduct was unlawful.

 

 We have agreed to indemnify each of our directors and certain officers against certain liabilities, including liabilities under the Securities Act of 1933. Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to our directors, officers and controlling persons pursuant to the provisions described above, or otherwise, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than our payment of expenses incurred or paid by our director, officer or controlling person in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, we will, unless in the opinion of our counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

 

ITEM 13.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements are included herein as required by Article 8 of Regulation S-X. See Index to Consolidated Financial Statements.

ITEM 14.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

At this time, there are no disagreements between the Company and its independent registered public accounting firm on accounting or financial disclosures. During the past two fiscal years or any later interim period our independent registered public accounting firm has neither resigned, declined to stand for re-election, nor been dismissed by our directors.

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ITEM 15.

FINANCIAL STATEMENTS AND EXHIBITS

 

Exhibit 3.1-		Articles of Incorporation
Exhibit 3.2-		Bylaws
Exhibit 4.1-		Example of Common Stock Certificate
Exhibit 4.2-		Form of Subscription Agreement with 25% Warrant Coverage
Exhibit 4.3-		Form of Subscription Agreement
Exhibit 4.4-		Form of Warrant Certificate
Exhibit 4.5-		2005 Incentive Compensation Plan
Exhibit 4.6-		Form of Option Agreement for Directors
Exhibit 10.1-		Production Payment with Blackrock Energy Capital
Exhibit 10.2-		Production Agreement with Blackrock Energy Capital
Exhibit 10.3-		Williamson Convertible Note for Days Creek Field
Exhibit 10.4-		Touhy Convertible Note for Days Creek Field
Exhibit 10.5-		Oilman Rig & Equipment Convertible Note for Days Creek Field
Exhibit10.6-		Kentucky Assignment from Advanced Methane
Exhibit 10.7-		Carl Landers-Maxim Patent Agreement
Exhibit 10.8-		Purchase and Sale Agreement with Carl Landers
Exhibit 10.9-		Orchard Petroleum- Joint Operating Agreement
Exhibit 10.10-		Orchard Petroleum- Joint Participation Agreement
Exhibit 10.11-		Separation Agreement with Robert McCann
Exhibit 10.12-		Power Hydraulics License Agreement
Exhibit 10.13-		Radial Drilling Services License Agreement
Exhibit 10.14-		Triton Daystar License Agreement
Exhibit 10.15-		Verdisys License Agreement
Exhibit 10.16-		Energy Capital Group Joint Venture and Assignment Contract
Exhibit 10.17-		Carl Landers Joint Venture Contract
Exhibit 10.18		Maxim Promissory Note, 2M- Greater European Funds
Exhibit 10.19-		Maxim Promissory Note, 19M- Greater European Funds
Exhibit 10.20-		Maxim Promissory Note, 20M- Greater European Funds

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Exhibit 10.21-		Subsidiary Security Agreement- Greater European Funds
Exhibit 10.22-		First Amendment to Security Agreement.-Greater European Funds
Exhibit 10.23-		Second Amendment to Security Agreement- Greater European Funds
Exhibit 10.24-		Form of Net Revenue Interest in KY and CA Fields for:
		Bioform, LLC, Harvey Pensack, and Jon Peddie
Exhibit 10.25-		Form of Overriding Royalty Interest in all Fields for:
		Frank Stack, Robert Newton, RF Petroleum, Greathouse Well Services, Harvey Pensack, Dipo Aluko, Jon Peddie, Louis Fusz Family Partnership, Stephan Baden, Wycap Corporation, and Michael Walsh
Exhibit 10.26-		Form of Orchard Revenue Sharing Agreement - Issued to Riderwood Investors
Exhibit 10.27-		Form of Oklahoma Revenue Sharing Agreement
Exhibit 10.28-		Form of Promissory Note for all Outstanding Convertible Promissory Notes, except those with Maxim TEP, PLC (Greater European Funds)
Exhibit 10.29-		Form of Wellbore Interest Agreement for:
		Baden Enterprise, Harvey Pensack, Judith Pensack Revocable Trust, Janice Peddie Living Trust, Jon Peddie Real Estate, and Jon Peddie.
Exhibit 10.30-		Form of Working Interest Agreement for:
		Baden Enterprise, Harvey Pensack, Judith Pensack Revocable Trust, Janice Peddie Living Trust, Jon Peddie Real Estate, and Jon Peddie
Exhibit 10.31-		Form of Wellbore Settlement for Baden Enterprise, Harvey Pensack, Judith Pensack Revocable Trust, Janice Peddie Living Trust, Jon Peddie Real Estate, and Jon Peddie
Exhibit 10.32-		Employment Agreement- W. Marvin Watson
Exhibit 10.33-		Addendum to Employment Agreement- W. Marvin Watson
Exhibit 10.34-		Assumed Purchase Agreement between Ergon Exploration and Interconn Resources, Inc.
Exhibit 10.35-		Convertible Notes for Days Creek Field Extension to April 30, 2008
Exhibit 10.36-		Employment Agreement- Dan Williams
Exhibit 10.37-		Employment Agreement- Dominic Maggio
Exhibit 10.38-		Employment Agreement- Robert Sepos
Exhibit 10.39-		Amendment No. 1 to the Maxim TEP, Inc. Incentive Compensation Plan dated March 21, 2007
Exhibit 10.40-		Amendment No. 2 to the Maxim TEP, Inc. Incentive Compensation Plan dated December 5, 2007
Exhibit 10.41-		Purchase And Sale Agreement by and between Maxim TEP Limited, Maxim TEP, Inc. and Upstream Capital Partners II Limited
Exhibit 10.42		Transfer Agreement by and between Maxim TEP, Inc. and Maxim TEP Limited dated April 3, 2008

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Exhibit 10.43		Term Sheet New Stream Energy
Exhibit 10.44		Consulting Agreement with Daniel Williams
Exhibit 10.45		Promissory note and mutual release agreement with Mr. Maggio
Exhibit 10.46		Promissory note, pledge and security agreement and mutual release agreement with Mr. Sepos
Exhibit 10.47		Revised production payment agreement with BlueRock
Exhibit 10.48		Registration rights agreement with Maxim TEP Limited
Exhibit 21-		List of Subsidiaries
Exhibit 23.1-		Consent of Pannell Kerr Foster of Texas, P.C.
Exhibit 23.2-		Consent of Aluko & Associates, Inc.
Exhibit 23.3-		Consent of Aluko & Associates, Inc. - for Delhi Field as of January 1, 2008
Exhibit 23.4-		Consent of Aluko & Associates, Inc. - for South Belridge Field as of January 1, 2008
Exhibit 23.5-		Consent of Haas Petroleum Engineering Services, Inc. - for Belton Field as of January 1, 2008
Exhibit 23.6-		Consent of Haas Petroleum Engineering Services, Inc. - for Stephens Field as of January 1, 2008
Exhibit 23.7-		Consent of Netherland, Sewell & Associates, Inc. - for Marion Field as of January 1, 2008
Exhibit 23.8-		Consent of Lee Keeling and Associates, Inc. - for Days Creek Field as of January 1, 2008
Exhibit 99.1-		Summary of Reserve Report of Aluko & Associates, Inc- for the Delhi field as of January 1, 2007
Exhibit 99.2-		Summary of Reserve Report of Aluko & Associates, Inc.- on South Belridge, Marion and Days Creek fields as of January 1, 2007
Exhibit 99.3-		Summary of Reserve Report of Aluko & Associates, Inc. - for Delhi Field as of January 1, 2008
Exhibit 99.4-		Summary of Reserve Report of Aluko & Associates, Inc. - for South Belridge Field as of January 1, 2008
Exhibit 99.5-		Summary of Reserve Report of Haas Petroleum Engineering Services, Inc. - for Belton Field as of January 1, 2008
Exhibit 99.6-		Summary of Reserve Report of Haas Petroleum Engineering Services, Inc. - for Stephens Field as of January 1, 2008
Exhibit 99.7-		Summary of Reserve Report of Netherland, Sewell & Associates, Inc. - for Marion Field as of January 1, 2008
Exhibit 99.8-		Summary of Reserve Report of Lee Keeling and Associates, Inc. - for Days Creek Field as of January 1, 2008

**  To be filed by amendment.

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SIGNATURES

 

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized.

 

Date: July 23, 2008	MAXIM TEP, INC.
	By:	/s/ W. Marvin Watson
		W. Marvin Watson
		Chief Executive Officer

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INDEX TO  CONSOLIDATED FINANCIAL STATEMENTS

 

	Page
Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheets as of December 31, 2007 and 2006	F-2
Consolidated Statements of Operations for the Years Ended December 31, 2007 and 2006	F-4
Consolidated Statements of Stockholders’ Deficit for the Years Ended December 31, 2007 and 2006	F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007 and 2006	F-8
Notes to Consolidated Financial Statements	F-11

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and

Stockholders of Maxim TEP, Inc.

We have audited the accompanying consolidated balance sheets of Maxim TEP, Inc. (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, cash flows and stockholders’ deficit 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 standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Maxim TEP, Inc. as of December 31, 2007 and 2006, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company has incurred significant operating losses and negative cash flows from operations since inception, has a working capital deficiency, and is in default on certain of its debt obligation which raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans with respect to this uncertainty are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

/s/ Pannell Kerr Forster of Texas, P.C.
Houston, Texas
June 10, 2008

F-1

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