Edgar Filing: MAXIM TEP, INC

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Amendment No. 2

FORM 10

General Form for Registration of Securities

Pursuant to Section 12(b) or (g) of the

Securities Exchange Act of 1934

MAXIM TEP, INC.

(Exact name of registrant as specified in its charter)

Texas		20-0650828
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

9400 Grogan’s Mill Road, Suite 205

The Woodlands, Texas 77380

www.maximtep.com

(Address of principal executive offices)

Registrant’s Telephone Number, Including Area Code: (281) 466-1530

Securities to be registered pursuant to Section 12(b) of the Act: None

Securities to be registered pursuant to Section 12(g) of the Act:

Common Stock, par value $0.00001

(Title of Class)

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o		Accelerated filer o

Non-accelerated filer o
(Do not check if a smaller reporting company)		Smaller reporting company x

MAXIM TEP, INC.

Table of Contents

		Page
PART I
ITEM 1.	BUSINESS	1
ITEM 2.	FINANCIAL INFORMATION	13
ITEM 3.	PROPERTIES	26
ITEM 4.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	28
ITEM 5.	DIRECTORS AND EXECUTIVE OFFICERS	30
ITEM 6.	EXECUTIVE COMPENSATION	34
ITEM 7.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	37
ITEM 8.	LEGAL PROCEEDINGS	40
ITEM 9.	MARKET PRICE OF AND DIVIDENDS ON THE COMPANY’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS	41
ITEM 10.	RECENT SALES OF UNREGISTERED SECURITIES	41
ITEM 11.	DESCRIPTION OF THE COMPANY’S SECURITIES	46
ITEM 12.	INDEMNIFICATION OF DIRECTORS AND OFFICERS	49
ITEM 13.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	49
ITEM 14.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES	49
ITEM 15.	FINANCIAL STATEMENTS AND EXHIBITS	50

SIGNATURES		53

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Forward Looking Statements

This Registration Statement on Form 10 contains forward-looking statements concerning our beliefs, plans, objectives, goals, expectations, anticipations, estimates, intentions, operations, future results and prospects, including statements that include the words “may,” “could,” “should,” “would,” “believe,” “expect,” “will,” “shall,” “anticipate,” “estimate,” “intend,” “plan” and similar expressions. These forward-looking statements are based upon current expectations and are subject to risk, uncertainties and assumptions, including those described in this Registration Statement on Form 10. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, estimated, expected, projected, intended, committed or believed. We provide the following cautionary statement identifying important factors (some of which are beyond our control) which could cause the actual results or events to differ materially from those set forth in or implied by the forward-looking statements and related assumptions.

PART I

ITEM 1. BUSINESS

(A) GENERAL

Maxim TEP, Inc. (“Maxim” or the “Company”), is headquartered in The Woodlands, Texas, a suburb of Houston. The Company is an oil and natural gas exploration, development and production (E&P) company geographically focused on the onshore United States. The Company’s operational focus is the acquisition, through the most cost effective means possible, of production or near production of oil and natural gas field assets. Targeted fields generally have existing wells that are often past primary energy recovery, but whose enhancement through secondary and tertiary recovery methods could revitalize them. Targeted fields also have the availability of additional drilling sites. The Company seeks to have an inventory of existing wells to enhance and a number of new drilling sites to maintain growth, while increasing reserves and cash flow. Maxim uses both conventional and non-conventional methods to bring non-producing wells back into production and to minimize operational costs.

(B) HISTORY AND DEVELOPMENT

During October of 2003, the founders conceived a business plan and named the Company Maxim Energy, Inc. On September 23, 2004 Maxim Energy, Inc. merged into Maxim TEP, Inc., a Texas corporation, which resulted in Maxim TEP, Inc. as the surviving entity headquartered in The Woodlands, Texas. The founders began to acquire oil and natural gas properties during 2004 with its first acquisition being a property in Oklahoma. Acquisition of properties continued in 2005 and 2006 and the Company now owns fields in Louisiana, Arkansas, Kentucky and New Mexico.

The Company has a three phases of development:

	§	Phase One – Acquisition Phase: Acquire property and oil and natural gas leases as budgets would allow while carefully selecting targeted properties that met the Company’s long range objectives.
	§	Phase Two – Development Phase: Drill development wells in careful “step outs” from known reserve areas to raise likelihood of productive new wells and enhance existing wells with secondary and tertiary recovery technologies available to the Company. The goal is to drill, complete and produce as much oil and natural gas as possible thereby increasing proved reserves and cash flows so as to support Phase Three.
	§	Phase Three – Expansion Phase: During this phase, the Company would continue to expand and replace production that it is selling into the market, offset historic decreases in production and monetize fields at appreciated values from their original purchase price.

Phase One – Acquisition Phase

The Company’s fundamental belief was premised on the proposition that oil prices would increase because world supplies were diminishing while worldwide demand was increasing. The founders are believers in “Peak Oil,” a belief that recognizes that since the production and extraction of oil and natural gas has grown almost every year and (It is currently at about 84 million barrels a day) production is likely to start a decline so we will have “peaked,” a theory first espoused by M. King Hubbert in the 1950’s who predicted the peak to occur between 1965-1970 and actually did occur in the lower 48 states in 1970-1971. Mr. Hubbert believed in the 1950’s, the world would use more than half its supply in the near future, then the industry would shift from a buyers’ market to a sellers’ market since oil production would more than likely stop growing and start a decline. The founders held that this decline would lead to higher prices and attention towards secondary and tertiary oil and gas recovery from older fields. By acquiring fields first, the belief was that prices would be lower than when the market realized the importance of older fields. Hence, many oil and natural gas fields were inexpensive as they were not economical, given the then-oil-and-gas prices. Nevertheless, these fields could become economical if oil and natural gas prices rose, giving the owner the potential to eventually monetize at higher energy prices.

The Company sought financing for its Phase One. Maxim secured initial funding from several accredited investors, and set out to acquire fields, and now currently owns the rights to oil and natural gas leases in Kentucky, Louisiana, Arkansas and New Mexico.

In buying existing oil and natural gas fields, the Company set out to extensively study the fields, the formations in which oil and natural gas were found, the history of sales from the field and the history of all surrounding fields, and their production. From this information, a better assessment could be made as to the value of the target property.

Phase Two – Development Phase

Phase Two is the monetization of the Company’s fields through secondary and tertiary recovery methods in existing wells, as well as the development through drilling of the undeveloped acreage that exist in its fields. The Company has the availability to workover over 530 wells through secondary and tertiary advanced stimulation methods. The Company also believes it has at least 2,159 drillable sites across all of its fields. This phase is highly dependent on the Company’s ability to secure funding from debt and equity sources.

Currently, the Company has active drilling, completion and operations on several of its fields located in Kentucky, Arkansas and Louisiana. The Company has 515 small productive natural gas wells in its Marion field in Louisiana that it received from the purchase of this field along with over 110 miles of natural gas gathering pipeline. It has plans to repair or put in place new pipeline to more efficiently capture additional natural gas from these existing wells. The Company began an eight-well drilling program in its Belton Field in Kentucky, resulting in three gas wells, three oil wells and one water well (for disposal purposes). The eighth well has not yet been drilled. The drilled wells are in different stages of completion. First production began in the fourth quarter of 2007. The Company has begun a workover program on existing wells in its Days Creek Field in Arkansas. The Company began four wells of a six-well drilling program in its Stephens Field in Arkansas, of which two are in production. Lastly, the Company has twelve oil wells in the Delhi Field in Louisiana and is beginning an active well workover program on them.

The Company initiated its Phase Two drilling and work-over program in late 2006 and early 2007. In 2008-09, Maxim intends to drill or enhance a total of 40 wells should it receive adequate funding.

In 2008-09 the Company plans to: work-over and enhance 10 existing oil wells and one injection well in the Days Creek Field; drill seven new wells in the Days Creek Field; workover 12 oil wells and four injection wells in Delhi Field; drill an injection well in the Belton Field; drill four wells in the deeper zone of the Stephens Field; and to complete one shallow well already drilled in the Stephens Field. While there are no assurances of success with all new wells, it is anticipated that this drilling plan, coupled with well enhancements in Marion and Delhi, could contribute significant additional production by December 2008.

The following table sets forth the Company’s 2008-09 planned oil and injection wells to drill or enhance.

	Wells Planned to Drill or Enhance in 2008-09		Active Wells December 2007
Marion–Louisiana		—		476
Days Creek–Arkansas		18		4
Delhi–Louisiana		16		—
Belton–Kentucky		1		2
South Belridge–California (sold in 2008)		—		9
Stephens (Deep)–Arkansas		4		2
Stephens (Jones)–Arkansas		1		—
Total		40		493

All of the planned drilling and enhancements assume that the Company is successful in securing its 2008 funding that will support a drilling and development budget of approximately $12.4 million. The actual number of wells drilled will vary depending upon various factors, including the availability and cost of drilling rigs, any working interest partner issues, our ability to raise additional capital, the success of our drilling programs, weather delays and other factors. If we drill the number of wells we have budgeted for 2008-09, depreciation, depletion and amortization, oil and natural gas operating expenses and production are expected to increase over levels incurred in 2007. Our ability to drill this number of wells is heavily dependent upon the timely access to oilfield services, particularly drilling rigs. The shortage of available rigs and financing in 2007 delayed the drilling and enhancement of several planned wells, slowing our growth in production. Due to limited funding, as of May 2008, the Company has only partially begun these planned 2008 activities and foresees the plan to extend into 2009, if funding is obtained.

Phase Three – Expansion Phase

In the Phase Three development of the Company, an effort will be made to replace the oil and natural gas reserves currently being developed in fields operated by the Company. Monetizing fields through the creation of Master Limited Partnerships (“MLP”) is also an option that offers cash flow to investors and the Company. With the enhanced oil recovery (“EOR”) methods available to the Company there are fields that it can acquire, either for development of reserves, enhancement, or monetization through resale. See EOR discussed in more detail on Page 7.

(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.

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

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.

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

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.

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.

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.

The Company sold oil and natural gas production representing more than 10% of its oil and natural gas revenues as follows:

	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.

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.

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.

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.

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.

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.

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.” If the carrying amount of the asset, including any intangible assets associated with that asset, exceeds its estimated future undiscounted net cash flows, the Company will recognize an impairment loss equal to the difference between its carrying amount and its estimated fair value. The fair value used to calculate the impairment for an individual producing oil and natural gas field is first determined by comparing the undiscounted future net cash flows associated with total proved producing properties to the carrying value of the underlying evaluated property. If the cost of the underlying evaluated properties is in excess of the undiscounted future net cash flows, the future net cash flows are used discounted at 10% to determine the amount of impairment. 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.

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.

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.

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.

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.

Liquidity and Capital Resources

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

At December 31, 2007, the Company had a working capital deficit of $59,195,129 consisting primarily of $48,969,797 in current debt, and $12,552,264 in accounts payable and accrued liabilities, offset by $166,412 of cash, $1,912,131 in receivables, $88,868 in inventories, and $159,521 of prepaid expenses and other current assets.

Net cash used in operating activities totaled $7,444,874 and $11,565,942 for 2007 and 2006, respectively. Net cash used in operating activities for 2007 consists primarily of the net loss of $29,985,540 and the increase in receivables of $1,107,493, offset by the net increase in accounts payable and accrued liabilities of $7,689,818, and by several non-cash charges including an impairment of oil and natural gas properties of $7,445,367, stock based compensation valued at $2,539,140, depletion, depreciation and amortization of $2,798,758, amortization of deferred financing costs of $1,332,482, and an impairment of investment of $1,365,712. The reduction in cash used in operating activities in 2007 as compared to 2006 was primarily due to the increase in revenues, the increase in common stock used to pay for services instead of cash, and the reduction in cash used with the significant increase in accounts payable and accrued liabilities.

Net cash provided by investing activities totaled $936,094 for 2007, compared to net cash used in investing activities of $26,076,315 for 2006. Net cash provided by investing activities for 2007 consists primarily of cash proceeds received of $2,250,000 from the sale of certain wells in the Delhi Field, cash proceeds of $620,000 from the sale of net revenue interests in several fields, and cash proceeds of $500,000 from the disposal of its investment in a fracturing technology. These 2007 cash inflows were offset by capital expenditures for oil and natural gas properties of $7,417,866, netted against a change in oil and natural gas property accrual and prepayments applied to those capital expenditures of $5,265,652. The change in cash provided by (used in) investing activities in 2007 as compared to 2006 was primarily due to the 2006 year including capital expenditures for oil and natural gas properties of $7,669,068, capital expenditures for property and equipment of $2,254,380, investments in a fracturing technology business of $1,535,712, and $8,987,721 of payments to the South Belridge Field operator for 2005 capital additions and a prepayment on 2007 capital additions to satisfy our promote funding commitment, offset by proceeds from sale of assets of $1,558,829, primarily from the sale of two drilling rigs and related equipment.

Net cash provided by financing activities totaled $3,709,299 and $40,458,607 for 2007 and 2006, respectively. Net cash provided by financing activities for 2007 consists primarily of proceeds from the sale of common stock and treasury stock, net of offering costs, of $3,385,349, and proceeds from new borrowings of $1,582,333, offset by payments on notes payable of $1,106,623. The reduction in cash provided by financing activities in 2007 as compared to 2006 was primarily due to the $37,400,000 borrowed from GEF. Net cash provided by financing activities for 2006 consists primarily of proceeds from new borrowings of $39,739,244 and proceeds from the sale of common stock of $5,050,650, offset by payment of financing costs of $2,723,619 and payments on notes payable of $1,357,668.

While the company is actively seeking additional funding sources, no future borrowing or funding sources are available under existing financing arrangements.

Off Balance Sheet Arrangements

ORRI Arrangements. Since inception, the Company has raised funds to acquire oil fields, and fund drilling costs and general working capital requirements, through the issuance and sale of debt and equity instruments as well as from the sale of various assets, including the sale and issuance of overriding royalty interests (“ORRI”) and revenue sharing agreements. The Company, based on its short term and long term funding needs, analyzes specific fields and the development requirements of the fields and, applying a cost benefit analysis, determines in which fields ORRI’s can be sold and the amount of the ORRI’s that can be sold. Senior management and field staff are involved in this analysis. Management then seeks approval from the Company’s Board of Directors prior to selling an ORRI or entering into a revenue sharing agreement. In certain cases, the Company reserves the right to repurchase certain ORRI’s in the future.

The following table summarizes the 8/8ths royalty interests (“RI”) and ORRIs assumed and issued by the Company as of December 31, 2007.

Investor Name	Date Issued		South Belridge Field (CA)			Days Creek Field (AR)			Stephens Field (AR)			Belton Field (KY)			Marion Field (LA)			Delhi Field (LA)			Hospah Field (NM)

RI and ORRI assumed in acquisition of property				25.00	%		25.00	%		25.00	%		6.25	%		23.00	%(a)		12.83	%
Oladipo Aluko		01/01/07					1.00	%		1.00	%								1.00	%
Greathouse Well Services, Inc.		01/01/07											3.13 (7 wells	% )
Robert L. Newton		01/01/07											4.00	%
Robert L. Newton		01/01/07											3.50 (3 wells	% )
Robert L. Newton		09/01/07																				10.0	%
Robert L. Newton		12/01/07					1.50	%
Robert L. Newton		12/01/07								10.00 (1 well	% )
Jon Peddie		03/01/07														25.00 (1 well	% )
Harvey Pensack		12/01/07					1.00	%
Harvey Pensack		12/01/07														8.50 (1 well	% )
Stephan Baden		03/01/07														25.00 (1 well	% )
Frank Stack		01/01/07											3.50 (3 wells	% )
Frank Stack		01/01/07											4.00	%
Frank Stack		12/01/07					1.50	%
Michael Walsh		12/01/07					1.00	%

(a)

Estimated average for the 499 wells acquired.

On the Belton Field in Kentucky, the Company assumed an ORRI to Advanced Methane Recovery (6.25%) that was originally in place upon the property’s purchase and granted a 4% ORRI to both Robert L. Newton and Frank Stack (on conversion of their 15% working interest from the Delhi property to this ORRI); and a 3.5% ORRI to both Robert L. Newton and Frank Stack, for additional cash infusions. A 3.125% ORRI was given to Greathouse Well Services, Inc. in each well drilled as supervised by them while under contract with the Company.

The Company issued an ORRI out of the Delhi, Days Creek and Stephens Field properties, granting a one percent (1%) ORRI interest out of each property to the Company’s reserve engineer in lieu of billings for certain engineering services related to these properties.

In Louisiana, on one well (McDermott Estate No. 5) the Company issued an 8.5% ORRI to Harvey Pensack; a 25% ORRI to Jon Peddie; and a 25% ORRI to Stephan Baden, as an incentive for them to loan the Company a total of $566,667.

To fund working capital needs, the Company sold a 1% ORRI to Board member Harvey Pensack on Days Creek, and sold an additional ORRI in this field to: Robert L. Newton 1.5%; Frank Stack 1.5%; and Michael Walsh 1% for cash consideration of $100,000 for every one percent (1%) ORRI or a corresponding equal percentage based on the consideration received.

The Jones #1 well is an isolated well next to the Stephens field that was purchased by the Company with partial financing from Mr. Newton who received a 10% ORRI on this well in consideration of his $50,000 investment.

During 2007, the Company sold a 10% ORRI in its Hospah leases for $70,000.

Net Revenue Interests. From time to time a Revenue Sharing Agreement (“RSA”) may be granted by the Company out of its 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 following table summarizes issued Revenue Sharing Agreements and amounts earned under those agreements during 2007 and 2006.

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.

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. In order to accomplish these goals, the Company’s capital requirements are an essential ingredient in both amount and timing. 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. 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).

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.

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.

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.

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. If net capitalized costs exceed this limit, discounted future net reserves applying a discount rate of 10% is used to compute an impairment which is charged to operations.

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.

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.

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.

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.

The following table sets forth certain information known to us as of May 31, 2008 with respect to each beneficial owner of more than five percent of the Company’s common stock. The percentage ownership is based on 125,474,313 shares of common stock outstanding as of May 31, 2008.

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.

The following table sets forth beneficial ownership of the Company’s common stock as of May 31, 2008 for each of the named executive officers and directors individually and as a group. The table includes any named executive officer or director that served in that capacity for any time during 2007 to May 31, 2008. The percentage ownership is based on 125,474,313 shares of common stock outstanding as of May 31, 2008.

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	%

(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.

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.

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.

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 but the Company will be in compliance with the guidelines set by the public market onto which it ultimately lists. For example, if the Company were subject to the independence requirements of the Nasdaq, all 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.

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.

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. 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

(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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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

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.

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.

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

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

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 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.

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: June 5, 2008	MAXIM TEP, INC.

	By:	/s/ W. Marvin Watson
		W. Marvin Watson
		Chief Executive Officer

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

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.

Consolidated Balance Sheets

	December 31,
	2007			2006

Assets

Current assets:
Cash and cash equivalents	$	166,412		$	2,965,893
Accounts receivable		1,548,131			468,080
Other receivable		364,000			477,688
Inventories		88,868			464,346
Prepayments to operator		–			3,694,739
Prepaid expenses and other current assets		107,721			205,087
Deferred financing costs, net		51,800			937,279

Total current assets		2,326,932			9,213,112

Oil and natural gas properties (successful efforts method of accounting):
Proved		25,819,764			21,146,409
Unproved		3,706,590			6,669,088
		29,526,354			27,815,497

Less accumulated depletion, depreciation and amortization		(3,783,700	)		(2,005,235	)

Oil and natural gas properties, net		25,742,654			25,810,262

Property and equipment:
Land		112,961			112,961
Buildings		240,500			240,500
Leasehold improvements		244,025			244,026
Office equipment and computers		79,769			68,198
Furniture and fixtures		211,581			205,749
Field service equipment and vehicles		738,463			621,763
Drilling equipment		174,082			215,868

		1,801,381			1,709,065

Less accumulated depreciation		(310,036	)		(154,867	)

Property and equipment, net		1,491,345			1,554,198

Intangible assets, net		4,881,302			5,727,615

Other assets		496,046			2,007,500

Total assets	$	34,938,279		$	44,312,687

See accompanying notes to consolidated financial statements

F-2

Maxim TEP, Inc.

Consolidated Balance Sheets (Continued)

	December 31,
	2007			2006

Liabilities and Stockholders’ Deficit

Current liabilities:
Accounts payable	$	4,144,402		$	1,280,004
Accounts payable to operators		1,071,089			103,802
Interest payable		5,202,148			550,486
Accrued payroll and related taxes and benefits		1,056,272			1,204,845
Accrued liabilities		1,078,353			594,420
Current maturities of notes payable, net of discount		43,808,772			38,638,247
Current maturities of notes payable, related party, net of discount		5,161,025			3,650,000

Total current liabilities		61,522,061			46,021,804

Notes payable, net of current maturities		1,750,000			6,000,000
Notes payable, related party, net of current maturities		1,250,000			700,000
Production payment payable		6,877,945			6,714,356
Deferred revenue		125,000			85,000
Asset retirement obligation		2,179,273			1,777,435

Total liabilities		73,704,279			61,298,595

Commitments and contingencies		–			–

Stockholders’ deficit
Preferred stock, $0.00001 par value; 50,000,000 shares authorized; zero shares issued and outstanding		–			–
Common stock, $0.00001 par value; 250,000,000 shares authorized; 85,604,516 and 77,146,581 shares issued and 85,579,516 and 76,813,248 shares outstanding at December 31, 2007 and 2006, respectively		856			771
Additional paid-in capital		50,477,255			42,521,892
Deferred stock based compensation		–			–
Accumulated deficit		(89,244,111	)		(59,258,571	)
Treasury stock, at cost; 25,000 and 333,333 shares at December 31, 2007 and 2006, respectively		–			(250,000	)

Total stockholders’ deficit		(38,766,000	)		(16,985,908	)

Total liabilities and stockholders’ deficit	$	34,938,279		$	44,312,687

See accompanying notes to consolidated financial statements

F-3

Maxim TEP, Inc.

Consolidated Statements of Operations

	Year Ended December 31,
	2007			2006

Revenues:
Oil and natural gas revenues	$	3,536,231		$	2,979,219
Drilling revenues		329,018			66,344
License fees, royalties and related services		257,500			377,500

Total revenues		4,122,749			3,423,063

Cost and expenses:
Production and lease operating expenses		2,992,812			1,725,211
Drilling operating expenses		1,059,168			324,628
Costs attributable to license fees and related services		178,820			616,496
Exploration costs		458,650			882,884
Revenue sharing royalties		165,418			389,757
Depletion, depreciation and amortization		2,798,758			1,760,401
Impairment of oil and natural gas properties		7,445,367			4,843,688
Impairment of investment		1,365,712			179,400
Penalties for late payments to operator		–			2,152,501
Loss on disposal of rigs		–			768,205
Accretion of asset retirement obligation		165,786			107,596
Alternative investment market fund raising activities		–			2,666,587
General and administrative expenses		8,644,418			8,157,225

Total cost and expenses		25,274,909			24,574,579

Loss from operations		(21,152,160	)		(21,151,516	)

Other income (expense):
Warrant inducement expense		–			(10,934,480	)
Interest expense, net		(8,847,238	)		(4,468,373	)
Loss on early extinguishment of debt		–			(234,630	)
Other miscellaneous income (expense), net		13,858			(33,510	)

Total other expense, net		(8,833,380	)		(15,670,993	)

Loss before income taxes		(29,985,540	)		(36,822,509	)

Income taxes		–			–

Net loss	$	(29,985,540	)	$	(36,822,509	)

Net loss per common share:
Basic and diluted	$	(0.37	)	$	(0.53	)

Weighted average common shares outstanding:
Basic and diluted		80,023,513			69,760,828

See accompanying notes to consolidated financial statements

F-4

Maxim TEP, Inc.

Consolidated Statements of Stockholders’ Deficit

For the Years Ended December 31, 2007 and 2006

	Common Stock				Additional Paid-In			Deferred Stock Based			Accumulated			Treasury			Total Stockholders’
	Shares		Amount		Capital			Compensation			Deficit			Stock			Deficit

Balance at December 31, 2005		44,327,940	$	443	$	19,167,293		$	(201,600	)	$	(22,436,062	)	$	–		$	(3,469,926	)

Deferred compensation reversal related to adoption of SFAS No.123(R)		–		–		(201,600	)		201,600			–			–			–

Common stock issued for cash		6,760,865		68		5,050,582			–			–			–			5,050,650

Common stock issued for services		2,011,500		20		1,508,605			–			–			–			1,508,625

Common stock issued to purchase intellectual assets		1,000,000		10		749,990			–			–			–			750,000

Common stock issued in exchange for cancellation of warrants		18,305,545		183		10,934,297			–			–			–			10,934,480

Common stock issued upon the conversion of debt and interest		3,042,023		30		2,281,486			–			–			–			2,281,516

Common stock issued upon the conversion of debt and interest, related party		365,375		4		274,027			–			–			–			274,031

Common stock issued to settle penalty fees		1,333,333		13		999,987			–			–			–			1,000,000

Purchase of common stock, 333,333 shares, at cost		–		–		–			–			–			(250,000	)		(250,000	)

Common stock offering costs		–		–		(176,184	)		–			–			–			(176,184	)

Common stock warrants issued as offering costs		–		–		176,184			–			–			–			176,184

Common stock warrants granted in connection with notes payable		–		–		102,111			–			–			–			102,111

Common stock warrants granted in connection with notes payable, related parties		–		–		86,942			–			–			–			86,942

Common stock warrants granted for services		–		–		443,352			–			–			–			443,352

Cancellation of common stock warrants		–		–		(9,855	)		–			–			–			(9,855	)

Stock based compensation - options		–		–		1,134,675			–			–			–			1,134,675

Net loss		–		–		–			–			(36,822,509	)		–			(36,822,509	)

Balance at December 31, 2006		77,146,581		771		42,521,892			–			(59,258,571	)		(250,000	)		(16,985,908	)

See accompanying notes to consolidated financial statements

F-5

Maxim TEP, Inc.

Consolidated Statements of Stockholders’ Deficit (Continued)

For the Years Ended December 31, 2007 and 2006

Common stock issued for cash

Common stock with put options issued for cash

266,666

–

Common stock issued as stock based compensation

Common stock issued to settle accrued payroll

Common stock issued upon the conversion of debt and interest

Common stock issued upon the conversion of debt and interest, related party

Common stock issued for oil and natural gas property

Common stock issued for oil and natural gas property, related party

Treasury stock issued for cash

–

244,000

Treasury stock issued to settle accrued payroll

–

6,000

Purchase of common stock, 25,000 shares, at cost

–

Common stock offering costs

Common stock warrants issued as offering costs

Common stock warrants issued in connection with notes payable, related party

Common stock warrants issued in connection with notes payable conversion

Common stock warrants issued in connection with notes payable conversion, related party

See accompanying notes to consolidated financial statements

F-6

Maxim TEP, Inc.

Consolidated Statements of Stockholders’ Deficit (Continued)

For the Years Ended December 31, 2007 and 2006

Common stock warrants issued to extend notes payable terms

Common stock warrants issued to extend notes payable terms, related party

Common stock warrants issued in connection with purchase of well bores and revenue sharing agreements

Common stock warrants issued in connection with purchase of well bores and revenue sharing agreements, related party

Common stock warrants issued in connection with sale of net revenue interests

Common stock warrants issued in connection with sale of net revenue interests, related party

Common stock options issued to employees as stock based compensation

Common stock options issued to non-employee directors as stock based compensation

Beneficiary conversion feature in connection with convertible note payable, related party

Balance at December 31, 2007

See accompanying notes to consolidated financial statements

F-7

Maxim TEP, Inc.

Consolidated Statements of Cash Flows

	Year Ended December 31,
	2007			2006

Cash flows from operating activities:
Net loss	$	(29,985,540	)	$	(36,822,509	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion, depreciation and amortization		2,798,758			1,760,401
Accretion of asset retirement obligation		165,786			107,596
Loss on disposal of rigs		–			768,205
Impairment of oil and natural gas properties		7,445,367			4,843,688
Impairment of investment		1,365,712			179,400
Amortization of debt discount		126,552			334,761
Amortization of deferred financing costs		1,332,482			2,015,609
Loss on early extinguishment of debt		–			234,630
Common stock issued to settle penalty fees		–			1,000,000
Common stock issued for services		–			1,508,625
Common stock warrants granted to non-employees for services		–			248,145
Stock based compensation		2,539,140			1,134,675
Warrant inducement expense		–			10,934,480
Changes in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable		(830,051	)		341,461
Other receivable		(277,442	)		(244,235	)
Inventories		207,124			(303,524	)
Prepaid expenses and other assets		(62,580	)		19,984
Accounts payable		912,629			340,738
Accounts payable to operators		967,287			(224,007	)
Accrued payroll and related taxes and benefits		645,492			(86,141	)
Interest payable and accrued liabilities		5,164,410			452,076
Deferred revenue		40,000			(110,000	)

Net cash used in operating activities		(7,444,874	)		(11,565,942	)

Cash flows from investing activities:
Acquisition of oil and natural gas properties		(50,000	)		(6,599,263	)
Proceeds from disposition of oil and natural gas property		2,250,000			–
Capital expenditures for oil and natural gas properties		(7,417,866	)		(7,669,068	)
Capital expenditures for property and equipment		(70,714	)		(2,254,380	)
Proceeds from sale of oil and natural gas equipment		50,000			1,558,829
Proceeds from sale of net revenue interests and sharing agreements		620,000			–
Change in oil and natural gas property accrual and prepayments		5,265,652			(8,987,721	)
Purchase of intangible assets		–			(250,000	)
Proceeds received from disposal of other assets		500,000			–
Investment in other assets		(225,000	)		(1,535,712	)
Proceeds from dividend on investments		14,022			–
Investment in certificates of deposit		–			(339,000	)

Net cash provided by (used in) investing activities		936,094			(26,076,315	)

See accompanying notes to consolidated financial statements

F-8

Maxim TEP, Inc.

Consolidated Statements of Cash Flows (Continued)

	Year Ended December 31,
	2007			2006

Cash flows from financing activities:
Proceeds from borrowings, production payment payable		–			222,000
Payment on production payment payable		(14,482	)		(55,338	)
Proceeds from issuance of notes payable		–			39,197,772
Payments on notes payable		(779,475	)		(644,525	)
Proceeds from issuance of notes payable, related parties		1,582,333			319,472
Payments on notes payable, related parties		(312,666	)		(657,805	)
Payment of financing costs		–			(2,723,619	)
Proceeds from issuance of common stock		2,941,349			5,050,650
Proceeds from issuance of common stock with put options		200,000			–
Proceeds from issuance of treasury stock		244,000			–
Purchase of treasury stock		–			(250,000	)
Purchase of treasury stock through put options		(18,750	)		–
Payment of common stock offering costs		(133,010	)		–

Net cash provided by financing activities		3,709,299			40,458,607

Increase (decrease) in cash and cash equivalents		(2,799,481	)		2,816,350

Cash and cash equivalents at beginning of year		2,965,893			149,543

Cash and cash equivalents at end of year	$	166,412		$	2,965,893

See accompanying notes to consolidated financial statements

F-9

Maxim TEP, Inc.

Consolidated Statements of Cash Flows (Continued)

	Year Ended December 31,
	2007		2006

Supplemental cash flow disclosures:
Cash paid for interest, net of amounts capitalized	$	1,889,215	$	1,825,574

Non cash financing and investing activities:
Notes payable and accrued interest exchanged for common stock	$	56,912	$	2,281,516
Notes payable and accrued interest exchanged for common stock, related party	$	202,126	$	274,031
Note payable exchanged for working interest in oil and natural gas well bores	$	1,750,000	$	–
Note payable exchanged for working interest in oil and natural gas well bores, related party	$	1,250,000	$	–
Common stock issued for working interest in oil and natural gas well bores	$	122,501	$	–
Common stock issued for working interest in oil and natural gas well bores, related party	$	157,499	$	–
Common stock issued to settle accrued payroll	$	788,065	$	–
Treasury stock issued to settle accrued payroll	$	6,000	$	–
Asset retirement obligation incurred	$	330,299	$	890,355
Intangible asset purchased with common stock	$	–	$	750,000
Notes payable, related party, issued to acquire intellectual property	$	–	$	3,650,000
Notes payable issued in connection with acquisition of oil and natural gas property	$	–	$	6,000,000
Notes payable issued to purchase property and equipment	$	–	$	500,000
Common stock warrants granted in connection with notes payable conversion	$	11,006	$	–
Common stock warrants granted in connection with notes payable conversion, related party	$	14,600	$	–
Common stock warrants granted in connection with notes payable	$	–	$	102,111
Common stock warrants granted in connection with notes payable, related party	$	91,264	$	86,942
Common stock warrants granted in connection with sale of net revenue interests	$	26,520	$	–
Common stock warrants granted in connection with sale of net revenue interests, related party	$	6,630	$	–
Common stock warrants granted to extend notes payable terms	$	145,521	$	–
Common stock warrants granted to extend notes payable terms, related party	$	259,210	$	–
Common stock warrants granted in connection with purchase of well bores and revenue sharing agreements	$	313,558	$	–
Common stock warrants granted in connection with purchase of well bores and revenue sharing agreements, related party	$	121,290	$	–
Common stock warrants granted as offering costs	$	1,308,559	$	176,184
Net joint interest billings exchanged for oil and natural gas property	$	374,370	$	–
Beneficial conversion feature in connection with convertible debt, related party	$	291,264	$	–
Revenue sharing agreements entered in connection with notes payable	$	–	$	108,663

See accompanying notes to consolidated financial statements

F-10

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 1 –

Financial Statement Presentation

Organization and nature of operations

Maxim TEP, Inc. was formed in 2004 as a Texas corporation to acquire, develop, produce and exploit oil and natural gas properties. Maxim Energy, Inc., Maxim TEP, Inc.’s predecessor, founded in 2003, was merged into Maxim TEP, Inc. in 2004. Maxim TEP, Inc. and its wholly owned subsidiaries (collectively referred to as the “Company”) have a patented technology for horizontal lateral drilling, the Landers’ Horizontal Drilling Technology (“LHD Technology”), a secondary enhancement technique designed to open lateral channels extending radially from the well bore or horizontally into the oil and natural gas reservoir. The Company’s major oil and natural gas properties are located in California, Kentucky, Arkansas, Louisiana and New Mexico. The Company’s executive offices are located in The Woodlands, Texas.

Going concern

As presented in the consolidated financial statements, the Company has incurred a net loss 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.

The accompanying consolidated financial statements are prepared as if the Company will continue as a going concern. The consolidated 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.

Note 2 –

Summary of Significant Accounting Policies

Principles of consolidation

The accompanying consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries after elimination of all material intercompany balances and transactions. Investments in entities in which the Company has a controlling interest are consolidated for financial reporting purposes. Investments in entities in which the Company does not have a controlling interest are accounted for under either the equity method or cost method of accounting, as appropriate. These investments are regularly reviewed for impairment and propriety of current accounting treatment.

Cash and cash equivalents

The Company considers all highly liquid investments, including money market accounts, with maturities of three months or less at the time of purchase to be cash and cash equivalents.

F-11

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 2 –

Summary of Significant Accounting Policies (Continued)

Concentration of credit risk

The Company maintains its cash with major U.S. banks. From time to time, cash amounts may exceed the federally insured limit of $100,000. The terms of these deposits are on demand to minimize risk. Historically, the Company has not incurred losses related to these deposits.

An allowance for doubtful accounts is recorded when it is determined that a customer or outside operator’s or purchaser’s account is not realizable in whole or in part. As of December 31, 2007 and 2006, the Company has not recorded any bad debt expense nor has it been required to record an allowance for doubtful accounts.

Major Customers

The Company sold oil and natural gas production representing more than 10% of its oil and natural gas revenues as follows:

	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.

Accounting estimates

F-12

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 2 –

Summary of Significant Accounting Policies (Continued)

Accounting estimates (continued)

Inventories

Inventories consist primarily of lateral rigs, drill pipe, spare parts, and other materials used in exploration and producing activities, and are valued at the lower of cost or market.

Deferred financing costs, net

Deferred financing costs incurred related to the Company’s various debt transactions are capitalized as incurred and are amortized to interest expense over the life of underlying loans using the effective interest method.

Oil and natural gas properties

The Company accounts for its oil and natural gas operations using the successful efforts method of accounting. Under this method, all costs associated with property acquisitions, successful exploratory wells, all development wells, including dry hole development wells, and asset retirement obligation assets are capitalized. Additionally, interest is capitalized while wells are being drilled and the underlying property is in development. Costs of exploratory wells are capitalized pending determination of whether each well has resulted in the discovery of proved reserves. Oil and natural gas mineral leasehold costs are capitalized as incurred. Items charged to expense generally include geological and geophysical costs, costs of unsuccessful exploratory wells, and oil and natural gas production costs. Capitalized costs of proved properties including associated salvage are depleted on a well-by-well or field-by-field (common reservoir) basis using the units-of-production method based upon proved producing oil and natural gas reserves. Oil and natural gas properties are also subject to impairment at each reporting period. Unproved property costs are excluded from depletable costs until the related properties are developed. See oil and natural gas property discussed in detail in Note 3 and impairment discussed in “Long-lived assets and intangible assets” below.

Property and equipment

Property and equipment are recorded at cost. Cost of repairs and maintenance are expensed as they are incurred. Major repairs that extend the useful life of equipment are capitalized and depreciated over the remaining estimated useful life. When property and equipment are sold or otherwise disposed, the related costs and accumulated depreciation are removed from the respective accounts and the gains or losses realized on the disposition are reflected in operations. The Company uses the straight-line method in computing depreciation for financial reporting purposes.

During the year ended December 31, 2006, the Company disposed of rigs that it had originally acquired for drilling purposes. Proceeds of $1,558,829 were received and a loss of $768,205 was recorded on the disposal.

Estimated useful lives of property and equipment are as follows:

Buildings	15-20 years
Leasehold improvements	Lease term (5 years)
Office equipment and computers	3-7 years
Furniture and fixtures	5 years
Field service equipment and vehicles	3-10 years
Drilling equipment	5-10 years

F-13

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 2 –

Summary of Significant Accounting Policies (Continued)

Long-lived assets and intangible assets

The Company accounts for intangible assets in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 142, "Accounting for Goodwill and Other Intangible Assets.” Intangible assets that have defined lives are subject to amortization over the useful life of the assets. Intangible assets held having no contractual factors or other factors limiting the useful life of the asset are not subject to amortization but are reviewed at least annually for impairment or when indicators suggest that impairment may be needed.

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 SFAS No. 144, “Accounting for the Impairment and Disposal of Long-Lived Assets.” If the carrying amount of the asset, including any intangible assets associated with that asset, exceeds its estimated future undiscounted net cash flows, the Company will recognize an impairment loss equal to the difference between its carrying amount and its estimated fair value. The fair value used to calculate the impairment for a producing oil and natural gas field that produces from a common reservoir is first determined by comparing the undiscounted future net cash flows associated with total proved properties to the carrying value of the underlying evaluated property. If the cost of the underlying evaluated property is in excess of the undiscounted future net cash flows, the future net cash flows are used discounted at 10% to determine the amount of impairment.

For unproved 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. Additionally, the Company recorded $250,000 as impairment of unproved oil and natural gas properties at December 31, 2007 as it decided to not pursue prospects in its Kansas property and allowed those leases to expire. There was no impairment of unproved properties required at December 31, 2006.

Asset retirement obligation

SFAS No. 143, “ Accounting for Asset Retirement Obligations,” requires that the fair value of the liability for asset retirement costs be recognized in an entity’s balance sheet, as both a liability and an increase in the carrying values of such assets, in the periods in which such liabilities can be reasonably estimated. The present value of the estimated future asset retirement obligation (“ARO”), as of the date of acquisition or the date at which a successful well is drilled, is capitalized as part of the costs of proved oil and natural gas properties and recorded as a liability. The asset retirement costs are depleted over the production life of the oil and natural gas property on a unit-of-production basis.

The ARO is recorded at fair value and accretion expense is recognized as the discounted liability is accreted to its expected settlement value. The fair value of the ARO liability is measured by using expected future cash outflows discounted at the Company’s credit adjusted risk free interest rate.

Amounts incurred to settle plugging and abandonment obligations that are either less than or greater than amounts accrued are recorded as a gain or loss in current operations. Revisions to previous estimates, such as the estimated cost to plug a well or the estimated future economic life of a well, may require adjustments to the ARO and are capitalized as part of the costs of proved oil and natural gas property.

F-14

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 2 –

Summary of Significant Accounting Policies (Continued)

Asset retirement obligation (continued)

The following table is a reconciliation of the ARO liability for the years ended December 31:

	2007			2006

Asset retirement obligation at beginning of year	$	1,777,435		$	779,484
Liabilities incurred		30,939			609,614
Revisions to previous estimates		299,360			280,741
Dispositions		(94,247	)		–
Accretion expense		165,786			107,596

Asset retirement obligation at end of year	$	2,179,273		$	1,777,435

Revenue recognition

The Company recognizes oil and natural gas revenues when sold. Volumes 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 offered. 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.

Financial instruments

The Company’s financial instruments consist of cash, receivables, payables and various debt instruments. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of these items. The Company’s various debt instruments approximate fair value as the underlying interest rates are commensurate with debt instruments carrying similar credit risk and maturity terms.

Income taxes

The Company accounts for income taxes in accordance with the provisions of SFAS No. 109, “Accounting for Income Taxes.” Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws and regulations. Deferred tax assets include tax loss and credit carryforwards and are reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Reclassifications

Certain reclassifications have been made to the 2006 financial statements to conform to the 2007 presentations. These reclassifications had no effect on the Company’s 2006 net income, or total assets, total liabilities, and stockholders’ deficit as of December 31, 2006.

F-15

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 2 –

Summary of Significant Accounting Policies (Continued)

Stock based compensation

Beginning January 1, 2006, the Company adopted SFAS No. 123(R), “Accounting for Stock Based Compensation,” to account for its Incentive Compensation Plan (the “2005 Incentive Plan”). Prior to January 1, 2006, the Company followed the provisions of SFAS No. 123. SFAS No. 123(R) requires all share-based payments to employees (which includes non-employee Board of Directors), including employee stock options, warrants and restricted stock, be measured at the fair value of the award and expensed over the requisite service period (generally the vesting period). The fair value of common stock options or warrants granted to employees is estimated at the date of grant using the Black-Scholes option pricing model by using the historical volatility of comparable public companies. The calculation also takes into account the common stock fair market value at the grant date, the exercise price, the expected life of the common stock option or warrant, the dividend yield and the risk-free interest rate.

Amortization of the calculated value of non-vested stock grants was accounted for as a charge to non-cash compensation expense, which is a component of General and administrative expenses, and an increase in additional paid-in-capital over the requisite service period. With the adoption of SFAS No. 123(R), the Company offset the remaining unamortized deferred compensation balance ($201,600 at December 31, 2005) in stockholders’ deficit against additional paid-in-capital. Amortization of the remaining unamortized balance will continue under SFAS No. 123(R) as described above.

Under the 2005 Incentive Plan, the Company from time to time may issue stock options, warrants and restricted stock to acquire goods or services from third parties. Restricted stock, options or warrants issued to other than employees or directors are recorded on the basis of their fair value, which is measured as of the date required by Emerging Issues Task Force (“EITF”) Issue 96-18, “ Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services.” In accordance with EITF 96-18, the options or warrants are valued using the Black-Scholes model on the basis of the market price of the underlying equity instrument on the “valuation date,” which for options and warrants related to contracts that have substantial disincentives to non-performance, is the date of the contract, and for all other contracts is the vesting date. Expense related to the options and warrants is recognized on a straight-line basis over the shorter of the period over which services are to be received or the vesting period.

Earnings per share

Basic earnings per share is computed using the weighted average number of common shares outstanding. Diluted earnings per share reflects the potential dilutive effects of common stock equivalents such as options, warrants and convertible securities. Due to the Company incurring a net loss during the years ended December 31, 2007 and 2006, basic and diluted loss per share are the same as all potentially dilutive common stock equivalents are anti-dilutive. Under SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” entities that have issued mandatorily redeemable shares of common stock or entered into forward contracts that require physical settlement by repurchase of a fixed number of the issuer’s equity shares of common stock in exchange for cash shall exclude the common shares that are to be redeemed or repurchased in calculating basic and diluted earnings per share. For the year ended December 31, 2007, the Company excluded 23,836 weighted average common shares outstanding for shares issued with put options that were recorded as a derivative liability, from its earnings per common share calculation.

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.

F-16

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 2 –

Summary of Significant Accounting Policies (Continued)

Recent unadopted 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 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.

F-17

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 3 –

Oil and Natural Gas Properties

California

During December 2004, the Company and Orchard Petroleum Inc. (“Orchard”) executed an agreement to jointly develop the 960-acre “Sledge Hamar” prospect, in the South Belridge Field located in Kern County, California. An option agreement was executed by and between the Company and Orchard for which the Company paid $600,000 during 2004 to Orchard for an exclusive right to enter into an Area of Mutual Interest and Joint Participation Agreement that was to expire on January 31, 2005, when a closing payment of $1,520,000 would be due.

An extension of the option agreement was executed on January 31, 2005. The Area of Mutual Interest and Joint Participation Agreement was executed on February 4, 2005 and the closing payment of $1,520,000 was made, of which $400,000 was applied to the Company’s drilling cost commitment. The agreement provided that for the initial investment and a commitment to fund 100% of the first $28.5 million costs of certain drilling operations, the Company will earn a 75% working interest of Orchard’s working interest in the Sledge Hamar prospect.

Further fundings of the drilling program to the extent amounts are in excess of $28.5 million will be shared by the Company and Orchard at their working interest percentages of 75% and 25%, respectively. During June 2006, the Company reached an agreement with Orchard regarding the future development of its California property, that in exchange for a 25% working interest in the remaining acreage to be developed in the Sledge Hamar prospect, the promotion of capital expenditures to be funded 100% by the Company was reduced to $23.5 million. As of December 31, 2006, the Company had funded all $23.5 million of its Joint Participation Agreement commitment, and at December 31, 2006, a total of $3,694,739 of that funding was recorded as current assets representing a prepayment to Orchard. The prepayment was subsequently applied to the Joint Participation Agreement commitment for wells drilled in 2007. 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.

During 2006, as a result of late payments to Orchard, the Company made several cash payments totaling $1,152,501 and issued 1,333,333 shares of company common stock to Orchard as late fees. The fair market value of the underlying common stock on the date of issuance was $0.75 per share with a total fair value of $1,000,000 (see Note 8). The Company recorded a total of $2,152,501 as penalties for late payments to operator to account for the late fees paid to Orchard during the year ended December 31, 2006.

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 comprised offsetting $374,370 of net joint interest billings owed to the Company, the issuance of $3,000,000 of 9% convertible notes payable maturing in October 2009 (see Note 5), the issuance of 373,333 shares of common stock, and the granting of 1,000,000 warrants with an exercise price of $0.75 per share. The notes are convertible into common stock of the Company at a conversion rate of $0.75 per dollar of principal. Of the total of the convertible notes, common stock and warrants issued, $1,250,000, 209,999 shares of common stock and 562,500 warrants to acquire common stock of the Company at $0.75 per share, respectively, were issued to related parties. The combined purchase price consideration was $3,869,996.

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. The estimated fair value of these warrants was determined using the Black-Scholes option pricing model and totaled $219,221 and was recorded as oil and natural gas properties.

F-18

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 3 –

Oil and Natural Gas Properties (Continued)

Louisiana

During September 2006, the Company executed a purchase and sale agreement with McGowan Working Partners, Inc., to purchase 100% of the membership interests in Delhi Oil and Gas, LLC (“Delhi”). The transaction was closed in December 2006. In conjunction with the acquisition, the Company entered into a separate purchase and sale agreement with a third party, RF Petroleum LA1, LLC (“RF Petroleum LA1”) to convey a 15% working interest in the surface and oil and natural gas leasehold in the Delhi Field if RF Petroleum LA1 put up a non-refundable down payment of $640,000. Upon execution of these two purchase and sale agreements, the Company was conveyed an 80.771% working interest and a 70.594% net revenue interest (“NRI”) in the Delhi Field covering approximately 1,400 acres in Richland Parish, Louisiana for a net total purchase price of $5,789,391 including legal fees. The field included 17 producing wells, of which 11 were shut in, eight water injection wells and one disposal well.

The Delhi purchase price allocation to the respective assets and liabilities acquired is as follows:

Other receivable	$	39,898
Oil and natural gas properties		5,696,857
Property and equipment		355,000
Liabilities assumed		(39,898	)
Asset retirement obligation		(262,466	)
Purchase price	$	5,789,391

Effective January 1, 2007, the Company exchanged a 8.0% net revenue interest in certain oil and natural gas properties in the Company’s Kentucky property and a payable of $375,000 for RF Petroleum LA1’s 15% working interest in the Delhi Field.

Effective May 1, 2007, the Company entered into a purchase and sale agreement with Denbury Onshore, LLC, to sell all of its interest in the Holt Bryant Sand formation of the Delhi property for $2,500,000, of which $250,000 was held in escrow for an environmental assessment. The transaction closed on June 1, 2007 and the Company assigned its 95.77% working interest in nine specific wells, and all associated easements, rights-of-way, support facilities and equipment related to these wells. The proceeds received were recorded as an adjustment to the cost of the property and no gain or loss was recorded.

Kansas

As a result of a settlement agreement effective December 20, 2005 between the Company and Metro Energy Group, Inc. (“Metro”), the Company received an assignment of a 100% working interest and a 81.25% NRI in certain oil and natural gas leases located in Barber County, Kansas covering approximately 640 acres. The value of the property was determined to be $250,000 based on management’s estimate of its fair value on the date of assignment. The Company decided in 2007 not to pursue any prospects on this property and has allowed all leases to expire. Accordingly, the Company has recorded an impairment of $250,000.

Arkansas

During November 2006, the Company entered into a purchase and sale agreement to acquire a 100% working interest (75% NRI) in oil and natural gas properties in Days Creek Field Unit (“Days Creek”) located in Miller County, Arkansas. In conjunction with the acquisition, the Company entered into a separate purchase and sale agreement with a third party, RF Petroleum AR1, LLC (“RF Petroleum AR1”), to convey a 15% working interest in all oil, natural gas and other mineral interest, equipment, and other interests in the Days Creek Field if RF Petroleum AR1 put up the non-refundable down payment of $675,000. Upon execution of these two purchase and sale agreements, the Company was conveyed an 85% working interest and a 63.75% NRI in the oil and natural gas properties in the Days Creek Field for a total purchase price of $6,080,245, of which $6,000,000 was financed by the issuance of three convertible notes payable to the sellers for $2,000,000 each (see Note 5).

F-19

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 3 –

Oil and Natural Gas Properties (Continued)

Arkansas (continued)

The Days Creek purchase price allocation to the respective assets and liabilities acquired is as follows:

Oil and natural gas properties	$	6,364,773
Property and equipment		60,903
Asset retirement obligation		(345,431	)

Purchase price	$	6,080,245

During the fourth quarter of 2007, the Company sold a 5% overriding royalty interests in the Days Creek oil and natural gas property and granted to these investors 150,000 warrants with an exercise price of $0.75 per share, generating total proceeds of $500,000. Of this sale, 1.0% overriding royalty interest and 30,000 warrants were granted to a related party for $100,000.

During 2006, the Company entered into an Asset Purchase and Sale Agreement for a total price of $400,630 including legal fees to acquire a 40% working interest in several 75% net working interest leases in Smackover Creek Field (“Smackover”) in Columbia County, Arkansas, covering approximately 1,114 acres. In a separate transaction, the Company later assigned a 16% working interest in the oil and natural gas properties in Smackover to Newton Petroleum AR1, LLC (“Newton”), a related party to RF Petroleum LA1 and RF Petroleum AR1, to acknowledge the down payments made in the purchase of the Delhi and Days Creek oil and natural gas properties.

The estimated fair value of this assigned interest totaled $160,000 and was recorded as other expense during the year ended December 31, 2006. This left the Company with a 24% working interest, but the Company also agreed to carry certain development costs of the seller, which gives the Company an effective 37.33% before casing point working interest.

In addition, Newton was also assigned a 40% ownership interest in the Company’s anticipated purchase of oil and natural gas properties in Clovis, New Mexico. As this acquisition has not been completed, no value has been recorded for the assignment during the years ended December 31, 2007 or 2006.

During 2007, the Company entered into a Purchase Agreement for a total price of $50,000 to acquire a 75% working interest with a 56.25% NRI in the Jones #1 well in the Stephens Field, but the Company also agreed to carry certain development costs of the seller, which gives the Company an effective 100% before casing point working interest. The Company later sold a 10% net revenue interest in the well for $50,000.

New Mexico

During 2007 and 2006, the Company made net payments aggregating $12,330 and $328,997, respectively, to purchase lease and various lease options in the Hospah and Lone Pine Oil and Gas Fields in McKinley County, New Mexico.

Exploratory well cost

Capitalized exploratory well cost of $1,450,277 are pending the determination of proved reserves at December 31, 2007. There were no capitalized exploratory well costs that were pending the determination of proved reserves at December 31, 2006.

F-20

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 4 –

Intangibles and Other Assets

During 2004, the Company entered into a joint venture agreement with a related party to utilize the LHD Technology and trade secrets, which is designed as a secondary enhancement technique for the purpose of stimulating oil and gas production by opening lateral channels extending radially from the well bore or horizontally into the oil and natural gas producing reservoir. The joint venture also includes the use of certain down-hole equipment. The agreement may be terminated by mutual consent of both parties at any time, and if for cause, termination must be in writing or may be terminated immediately in writing should the Company cease doing business or for other causes, as defined. At December 2007 and 2006, the Company has recorded $15,000 as an intangible asset to account for the license to use the LHD Technology and related trade secrets.

During 2004, the Company commenced negotiations with a related party to acquire their rights, title and interest in the LHD Technology, which is held by a patent, for a total price of $4,750,000 comprised of $4,000,000 of cash and 1,000,000 shares of the Company’s common stock valued at $0.75 per share or $750,000. A payment of $100,000 was made in 2005 as initial consideration while in negotiations. Effective September 12, 2006, the Company and the related party reached a final agreement to acquire the LHD Technology for an additional cash payment of $250,000, the issuance of two notes payable to the seller totaling $3,650,000 (see Note 5) and the issuance of 1,000,000 shares of common stock at fair market value of $0.75 per share (see Note 8).

The Company has recorded $4,750,000 as intangible assets at December 31, 2007 and 2006 to account for the purchase agreement. The patent expires in 2013 and is being amortized over the life of the patent using the straight line method. At December 31, 2007 and 2006, accumulated amortization totaled $335,483 and $169,643, respectively.

Effective March 8, 2005, the Company entered into an assignment of a license agreement with Verdisys, Inc. (“Verdisys”) whereby Verdisys will assign all its right, title, and interest in its LHD Technology License (“Verdisys License”) for total cash consideration of $1,300,000. The patent expires in 2013 and the license is being amortized over the life of the patent using the straight line method. At December 31, 2007 and 2006, accumulated amortization totaled $848,215 and $167,742, respectively.

As of December 31, 2007 and 2006, management believes that the LHD Technology assets referred to above are fully realizable, thus no impairment is required.

The Company owns an equity interest in Alchem Field Services, Inc. (“Alchem”) which is recorded on a cost basis. At December 31, 2006 the Company reviewed the investment for impairment and determined that the investment had decreased in value. Accordingly, an impairment of $179,400 was recorded at December 31, 2006, to reflect the net recoverable value of the investment estimated to be approximately $21,000. During 2007, the Company received $14,022 in dividends which it offset against the carrying value of the investment.

Effective May 15, 2005, the Company entered into a purchase agreement with Edge Capital Group, Inc. (“ECG”) whereby ECG will convey, transfer, and deliver its rights to a license of the LHD Technology to the Company for a total consideration of $500,000. Payments were expected to be made in several installments and the title to be transferred and delivered upon the final payment. Total payments aggregating $75,000 were recorded as other assets as of December 31, 2006. During 2007, the Company decided not to continue with the purchase of this license and wrote off the $75,000 in non-refundable installment payments previously capitalized.

Effective September 26, 2006, the Company entered into a purchase agreement with J Integral Engineering, Inc. (“JIE”) for the acquisition of 100% of the common stock of JIE for a total purchase price of $6,000,000. JIE had a technology to fracture formations that fit the Company’s technology enhancement business plan. Several restrictions in the purchase agreement prevented the Company from having control of this business until the purchase price consideration was paid in full, therefore partial payments were recorded as other assets. Total payments including direct legal expenses aggregating $1,565,712 were recorded as other assets as of December 31, 2006. In May 2007, the purchase agreement between the Company and JIE was mutually terminated by the two parties and the transaction unwound. A loss of approximately $1.1 million was recorded during 2007 related to the abandonment of this investment.

F-21

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 4 –

Intangibles and Other Assets (Continued)

During 2007, the Company spent $225,000 toward the purchase of a pipeline in Kentucky. In December 2007, the Company decided to abandon the purchase of this pipeline and recorded an impairment of $225,000.

During 2006, the Company purchased two certificates of deposit totaling $300,000, of which $250,000 and $50,000 are collateral for letters of credit required by the State of Louisiana and Ergon Exploration, Inc. (“Ergon”), respectively, as financial security to be an operator in the state. The certificates of deposit mature on September 6, 2008 and are subject to automatic extension for a period of twelve months on each successive expiration date unless terminated upon mutual agreement. The certificates of deposit have been recorded on the long-term basis within other assets.

Intangible assets consisted of the following at December 31:

	2007			2006

LHD Technology Joint Venture	$	15,000		$	15,000
LHD Technology Patent		4,750,000			4,750,000
Verdisys License		1,300,000			1,300,000

		6,065,000			6,065,000

Accumulated amortization		(1,183,698	)		(337,385	)

Intangible assets, net	$	4,881,302		$	5,727,615

Future amortization expense related to license and patent agreements is as follows:

2008	$	846,313
2009		846,313
2010		846,313
2011		846,313
2012		846,313
Thereafter		634,737

	$	4,866,302

F-22

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 5 –

Debt

Notes payable

Notes payable consists of the following at December 31:

	2007			2006

Notes payable	$	400,000		$	1,229,475
Notes payable, related party		3,597,001			3,650,000
Convertible notes payable		45,158,772			43,408,772
Convertible notes payable, related party		3,270,000			700,000

		52,425,773			48,988,247

Less unamortized debt discount		(455,976	)		–

		51,969,797			48,988,247
Less current maturities:
Notes payable, net of discount		(43,808,772	)		(38,638,247	)
Notes payable, related party, net of discount		(5,161,025	)		(3,650,000	)

Notes payable, net of current maturities and discount	$	3,000,000		$	6,700,000

The Company held notes payable with various individual investors aggregating $400,000 and $700,000 at December 31, 2007 and 2006, respectively. These notes payable with individuals mature from May 1, 2007 to September 30, 2007 bearing interest at fixed rates of 9%. Simple interest will accrue from the note issue date and is due and payable either at maturity or quarterly or semi-annually until maturity. The Company is in default on notes payable of $400,000 at December 31, 2007 and is in the process of renegotiating its terms. This notes payable in default is accruing interest at a higher rate and additional late fees may apply. This notes payable is unsecured.

During 2006, the Company issued a $500,000 promissory note to an individual in connection with the purchase of a drilling rig. The note matured on January 2, 2007 and did not bear interest. The outstanding balance on this note at December 31, 2006 was $500,000, and the Company paid off the note during 2007.

In September 2006, the Company issued a $39,000 promissory note to a financial institution in connection with the purchase of an automobile. The note matured on September 12, 2007, and bore interest at 5.5% per annum, payable in monthly installments of $3,349. The note was secured by the purchased automobile. The outstanding balance on this note at December 31, 2006 was $29,475, and the Company paid off the note during 2007.

Effective September 12, 2006, the Company and a related party entered into a formal purchase and sale agreement to purchase their right, title and interest in the LHD Technology for a total purchase price of $4,750,000 comprised of $4,000,000 of cash and 1,000,000 shares of the Company’s common stock valued at $750,000 (see Note 4). During 2006, as part of the payment consideration, the Company issued two notes payable to the seller totaling $1,650,000 and $2,000,000, respectively. These notes payable matured on June 1, 2007 and December 31, 2007, respectively, and interest accrued at a fixed interest rate of 8% starting from January 1, 2007 and January 1, 2008, respectively, until the amounts are paid. The Company had a total of $3,578,000 and $3,650,000 outstanding at December 31, 2007 and 2006, respectively. Subsequent to December 31, 2007, the lender converted the entire $3,578,000 of the outstanding notes payable into shares of the Company’s common stock at $0.75 per share.

F-23

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 5 –

Debt (Continued)

Notes payable (continued)

During 2007, the Company borrowed $262,333 from officers of the Company. These notes matured on December 31, 2007 and did not bear interest. As of December 31, 2007, $240,666 was repaid and $2,666 was offset against a receivable, leaving a remaining $19,001 outstanding. These notes were in default at December 31, 2007, but have been repaid or renegotiated in the first quarter of 2008.

During 2007 and 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 $50,000 and $2,216,667 of principal and $6,912 and $15,993 of accrued interest into 75,883 and 2,976,879 shares of the Company’s common stock during 2007 and 2006, respectively. Because of the early extinguishment, any unamortized debt discount or loan origination costs were recorded as loss on early extinguishment of debt, as discussed in more detail below under “Loss on early extinguishment of debt.”

Convertible notes payable

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 notes payable are convertible into shares of the Company’s common stock at an exchange rate of $0.75 per share, or into 49,878,363 shares of common stock. These notes are secured by certain oil and natural gas properties of the Company. During 2007, these notes went into default and are currently accruing interest at default rates of 10% and 18%, respectively. In April 2008, the Company and Maxim TEP, PLC entered into further agreements related to these promissory notes (see Note 15).

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 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.

During October 2007, the Company reacquired various working interests in certain wells located in the South Belridge field from several individuals. The purchase price consideration comprised offsetting $388,463 of joint interest billings owed to the Company, the issuance of $3,000,000 of 9% convertible notes payable maturing in October 2009, the issuance of 373,333 shares of common stock, and the granting of 1,000,000 warrants with an exercise price of $0.75 per share. The notes are convertible into common stock of the Company at a conversion rate of $0.75 per dollar of principal. Of the total of the convertible notes, common stock and warrants issued, $1,250,000, 209,999 shares of common stock and 562,500 warrants to acquire common stock of the Company at $0.75 per share, respectively, were issued to related parties.

F-24

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 5 –

Debt (Continued)

Convertible notes payable (continued)

During 2005, the Company executed a convertible notes payable with a related party investor aggregating $700,000. This notes payable matured March 29, 2007 bearing interest at a fixed rate of 9%. Simple interest will accrue from the note date and is due and payable quarterly until maturity. Should the 9% convertible note go into default, interest will accrue at a rate of 18%. The note is unsecured. This note payable is convertible into shares of the Company’s common stock at an exchange rate of $0.75 per share, or into 933,333 shares of common stock. At December 31, 2007 and 2006, the Company had $700,000 outstanding of convertible notes payable to this investor. The maturity date on this note was extended to mature on September 30, 2007 and then extended again to March 30, 2008, whereby the Company issued the note holder warrants to purchase 466,666 shares of the Company’s common stock at an exercise price of $0.75 per share for a period of five years and then issued warrants to purchase another 466,666 shares of the Company’s common stock at an exercise price of $0.75 per share for a period of three years, as fees for the extensions. The fair value of the warrants are being amortized to interest expense using the interest method over the extension periods. The note payable bears interest at 12% from October 1, 2007 through March 30, 2008 and 18% in the event of default. The Company is currently in default on this note payable and is in negotiations with the note holder.

During 2007, the Company borrowed $120,000 from related party individuals at 9% per annum, maturing from November 13, 2007 to June 1, 2008. The entire outstanding balance at December 31, 2007 of $120,000 was converted into 160,000 share of the Company’s common stock on March 28, 2008.

During the fourth quarter of 2007, the Company borrowed an additional $1,000,000 from a related party issuing notes payable for $1,200,000 with a 20% imputed interest rate, maturing in one year from the note date. The notes are convertible into common stock of the Company at a conversion rate of $0.75 per dollar of principal.

During 2007 and 2006, several note holders converted $200,000 and $301,125 of principal of their notes and $2,126 and $21,762 of corresponding accrued interest into 269,501 and 430,519 shares, respectively, of the Company’s common stock at an exchange rate of one share for each $0.75 of principal and interest converted. In case of early extinguishment, any unamortized debt discount or loan origination costs were recorded to interest expense, as discussed further below.

At December 31, 2007 should all the convertible note holders execute their right to convert, the Company would be obligated to issue 60,571,696 shares of the Company’s common stock. In 2008, a significant amount of outstanding debt was repaid or converted into common stock (see Note 15).

Beneficial conversion features

From time to time, the Company may issue convertible notes that have detached warrants and may contain an imbedded beneficial conversion feature. A beneficial conversion feature exists on the date a convertible note is issued when the fair value of the underlying common stock to which the note is convertible into is in excess of the remaining unallocated proceeds of the note after first considering the allocation of a portion of the note proceeds to the fair value of the warrants, if related warrants have been granted. In accordance with EITF 00-27 “Application of Issue No. 98-5 to Certain Convertible Instruments,” the intrinsic value of the beneficial conversion feature is recorded as a debt discount with a corresponding amount to additional paid in capital. The debt discount is amortized to interest expense over the life of the note using the interest method. During the year ended December 31, 2007, beneficial conversion features related to convertible notes payable totaling $291,264 were recorded, all of which was attributable to related parties.

Detachable common stock warrants

In addition to their rights to receive principal and interest, certain note holders were granted fully vested warrants to purchase shares of the Company’s common stock with an exercise price of $0.75 per share expiring three to five years from the date of the note.

F-25

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 5 –

Debt (Continued)

Detachable common stock warrants (continued)

During the years ended December 31, 2007 and 2006, certain note payable agreements provided for warrants to purchase a total of 470,000 shares and 825,000 shares of the Company’s common stock at an exercise price of $0.75 per share, respectively, of which warrants to purchase 470,000 shares and 375,000 shares were issued to related parties, respectively. The fair value of the warrants was determined using the Black-Scholes option pricing model and was recorded as a debt discount totaling $91,264 and $189,053 during the years ended December 31, 2007 and 2006, respectively.

The debt discount is being amortized to interest expense over the life of the notes using the straight line method. Upon the repayment or conversion of a note payable into the Company’s common stock, any remaining unamortized debt discount is charged to interest expense or loss on early extinguishment of debt.

During 2007, warrants to acquire 1,366,331 shares of the Company’s common stock with an exercise price of $0.75 per share, expiring three to five years from the date of grant, were granted to four note holders to extend the maturity date of their notes payable totaling $1,350,000. The fair value of each warrant was estimated on the note extension date using the Black-Scholes option pricing model. The estimated fair value of these warrants totaled $395,265. In addition, warrants to acquire 45,000 shares of the Company’s common stock with an exercise price of $0.75 per share, expiring three years from the date of grant, were granted to note holders for extending the payment date of $67,500 of accrued interest on their notes payable totaling $3,000,000. The fair value of each warrant was estimated on the note extension date using the Black-Scholes option pricing model. The estimated fair value of these warrants totaled $9,466.

Net revenue interest

In addition to their rights to receive principal and interest, certain note holders were granted either a net revenue interest in certain of the Company’s oil and natural gas properties or a revenue sharing agreement with the Company. Certain present and past note holders have been conveyed certain of the following interests in the Company’s oil and natural gas activities:

During 2006 an aggregate 2.2% revenue sharing agreements in seven wells owned by the Company in South Belridge, California was granted to certain noteholders. The fair value of the revenue sharing agreements were determined based on the present value of the underlying wells’ future net cash flows discounted at 10% and recorded as a debt discount totaling $108,663 during the year ended December 31, 2006. The debt discount was fully amortized to interest expense in 2006, as all the related debt was all converted to common stock during 2006.

During 2006, an aggregate 58.5% overriding royalty interest, as defined, in a certain single well to be drilled in Union Parish, Louisiana, was granted to certain noteholders. The fair value of the overriding royalty interest was determined to be zero at the grant date due to the uncertainty that a well would be drilled and if drilled that it would be economically productive.

F-26

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 5 –

Debt (Continued)

Interest expense, net

Interest expense consists of the following for the years ended December 31:

	2007			2006

Interest expense related to debt	$	7,117,875		$	2,324,433
Amortization of deferred financing costs		1,332,482			2,015,609
Amortization of debt discount		126,552			334,761
Interest expense related to stock put options		333,333			–
Capitalized interest		(42,125	)		(141,985	)
Interest income		(20,879	)		(64,445	)

	$	8,847,238		$	4,468,373

Loss on early extinguishment of debt

During the year ended December 31, 2006, various debt instruments were extinguished prior to their maturity dates. At the time of extinguishment, any remaining unamortized debt discount or loan origination costs were either charged to interest expense (convertible notes) or recorded as a loss on early extinguishment of debt. During the year ended December 31, 2006, $234,630 was recorded as loss on early extinguishment of debt.

Note 6 –

Production Payment Payable

During 2005, the Company entered into a production payment payable with a reputable third party financial institution that provides for total borrowings of up to $6,802,000, of which $222,000 and $6,275,000 was funded during 2006 and 2005, respectively. Of the proceeds received in 2005, $6,250,000 was used to acquire all the rights, title and interest in leases covering approximately 22,000 acres and 500 well bores owned by Ergon in the Monroe Gas Rock Field, Union Parish, Louisiana. The production payment payable is secured by the underlying property. Principal and interest will be paid out of production from the underlying property equal to 56% of the Company’s share of revenue produced until the principal has been repaid in full and an 18% internal rate of return is obtained by the financial institution. When the production payment payable has been repaid in full it will be terminated and replaced with a permanent 3% overriding royalty interest in the properties.

During 2007 and 2006, production payments made to the financial institution were not sufficient to meet the aforementioned internal rate of return of 18%, therefore, the outstanding balance of the production payment payable was increased to accrue for the unpaid interest expense. At December 31, 2007 and 2006, the Company has a total of $6,877,945 and $6,714,356 outstanding as production payment payable, respectively.

F-27

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 7 –

Off Balance Sheet Arrangements

Net Revenue Interests

The following table summarizes issued RSAs and amounts earned under those agreements during 2007 and 2006.

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.

ORRI Arrangements

Since inception, the Company has raised funds to acquire oil fields, and fund drilling costs and general working capital requirements, through the issuance and sale of debt and equity instruments as well as from the sale of various assets, including the sale and issuance of overriding royalty interests (“ORRI”). The Company, based on its short term and long term funding needs, analyzes specific fields and the development requirements of the fields and, applying a cost benefit analysis, determines in which fields ORRI’s can be sold and the amount of the ORRI’s that can be sold. In certain cases, the Company reserves the right to repurchase certain ORRI’s in the future. The fair value of these ORRIs at the grant date are recorded as a reduction in the carrying value of the related oil and natural gas property.

F-28

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 7 –

Off Balance Sheet Arrangements (Continued)

In Louisiana, on one well (McDermott Estate No. 5) the Company issued an 8.5% ORRI to Harvey Pensack; 25% ORRI to Jon Peddie; and 25% ORRI to Stephan Baden, also in consideration of cash infusion.

During the fourth quarter of 2007, the Company sold a 5% ORRI in the Days Creek oil and natural gas property and granted to these investors 150,000 warrants with an exercise price of $0.75 per share, generating total proceeds of $500,000. Of this sale, 1.0% ORRI and 30,000 warrants were granted to a related party for $100,000.

During 2007, the Company sold a 10% ORRI in its Hospah leases for $70,000.

Note 8 –

Stockholders’ Equity

Preferred stock

The Company has preferred stock, $0.00001 par value, 50,000,000 shares authorized with zero shares issued and outstanding as of December 31, 2007 and 2006. The terms of the preferred shares are to be determined at the time of issuance.

Common stock

The Company has common stock, $0.00001 par value, 250,000,000 shares authorized. From time to time, common stock may be issued for goods and services, the fair value of these transactions has been determined based on recent cash transactions where common stock has been sold to investors or the fair value of the underlying transactions, whichever is more determinable.

During 2007 and 2006, total proceeds of $3,141,349 and $5,050,650 were generated through private offerings of common stock from the issuance of 4,188,465 and 6,760,865 shares, respectively, at $0.75 per share. Of the total number of common shares sold during the years ended December 31, 2007 and 2006, 100,000 and 466,667 shares were sold to related parties generating proceeds of $75,000 and $350,000, respectively. Of the total number of common shares sold in 2007, 266,666 shares included embedded put options at $2.00 per share, which originally expired on December 15, 2007, but were extended to August 31, 2008. These shares with embedded put options were recorded at their par value and the excess obligation over the par value was recorded as a derivative, which is recorded within accrued liabilities.

During 2007 and 2006, the Company issued 3,550,753 and 2,011,500 shares of common stock with a fair value of $0.75 per share with a total fair value of $2,663,065 and $1,508,625, respectively, for services. In 2007, all shares issued were to employees for compensation or salary conversion. In 2006 all shares issued were to third parties for services.

During 2007 and 2006, note holders comprising $259,038 and $2,555,547 of principal and accrued interest elected to convert into 345,384 and 3,407,398 shares of the Company’s common stock, respectively, at an exchange rate of one share for each $0.75 of principal (see Note 5).

F-29

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 8 –

Stockholders’ Equity (Continued)

Common stock (continued)

During 2006, the Company issued 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 (see Note 4).

In order to reduce the number of warrants outstanding during 2006, the Company offered warrant holders an option to exchange their warrants for common stock on a four for five basis. Accordingly, the Company issued 18,305,545 shares of common stock to warrant holders and cancelled 22,915,255 warrants, with an original exercise price of $0.75 per share. Management’s estimate of fair market value of the underlying common stock on the date of the exchange was $0.75 per share. The Company recorded $10,934,480 as warrant inducement expense within other income (expense) during 2006 to account for the excess fair value of the common stock over the original estimate of the fair value of the underlying warrants.

During 2006, the Company repurchased 333,333 shares of the Company’s common stock for a total cost of $250,000, and these shares were held in treasury. During 2007, the Company sold 325,334 shares held in treasury for total proceeds of $244,000 and issued 7,999 shares held in treasury in payment of $6,000 in compensation. In 2007, 25,000 shares of the Company’s common stock were put to the Company at $2.00 per share, of which the par value of $0.00001 per share was recorded as the cost of the treasury shares and the remainder applied to put option derivative liability.

Warrants

During 2007 and 2006, warrants to acquire 4,356,887 and 562,163 shares, respectively, of the Company’s common stock with an exercise price of $0.75 per share were granted in connection with the sale of the Company’s common stock. These warrants expire five years from the date of grant. Of these warrants issued in 2007, 2,018,750 were granted to related parties. The estimated fair value of the warrants was determined using the Black-Scholes option pricing model and totaled $1,308,559 and $176,184, respectively, and was recorded as common stock offering costs included in additional paid-in capital during 2007 and 2006, respectively.

During 2007 and 2006, the Company entered into various note payable agreements with related and unrelated third party investors to fund its operations (see Note 5 under the caption “Detachable common stock warrants”). At December 31, 2007 and 2006, certain note payable agreements provide for warrants to purchase a total of 470,000 and 825,000 of the Company’s common stock, respectively, at an exercise price of $0.75 per share of which 470,000 shares and 375,000 shares were granted to related parties, respectively. These warrants expire three or five years from the date of grant. The fair value of these warrants was determined using the Black-Scholes option pricing model and was recorded as a debt discount totaling $91,264 and $189,053 during the years ended December 31, 2007 and 2006, respectively. The debt discount is being amortized to interest expense over the life of the notes using the straight line method.

During 2007, warrants to purchase 1,411,331 shares of the Company’s common stock with an exercise price of $0.75 per share were granted to certain note holders for extending the terms of their notes payable (see Note 5). These warrants expire five years from the date of grant. Of these warrants issued, 933,332 were issued to related parties. The estimated fair value of these warrants was determined using the Black-Scholes option pricing model and totaled $404,731.

F-30

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 8 –

Stockholders’ Equity (Continued)

Warrants (continued)

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 (see Note 3). The estimated fair value of these warrants was determined using the Black-Scholes option pricing model and totaled $219,221 and was recorded oil and natural gas properties.

During 2007, the Company sold a 5% net revenue interest in the oil and natural gas properties 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. The estimated fair value of these warrants was determined using the Black-Scholes option pricing model and totaled $33,150 and was recorded as additional paid-in capital.

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 provided during 2006. These warrants expire five years from the date of grant. The estimated fair value of these warrants was determined using the Black-Scholes option pricing model to be $443,352 and was recorded as general and administrative expense or other expense based on the nature of service provided.

The following is a summary of the warrant activity for the years ended December 31:

	2007				2006
	Number of Shares		Weighted Average Exercise Price		Number of Shares			Weighted Average Exercise Price

Outstanding, beginning of year		5,597,494	$	0.75		25,904,271		$	0.75

Granted		8,492,452		0.75		2,675,978			0.75
Exercised		–		–		(22,915,255	)		0.75
Expired or cancelled		–		–		(67,500	)		0.75

Outstanding, end of year		14,089,946	$	0.75		5,597,494		$	0.75

Exercisable, end of year		14,089,946	$	0.75		5,597,494		$	0.75

The weighted remaining contractual life of outstanding and exercisable warrants at December 31, 2007 is 3.3 years.

F-31

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 8 –

Stockholders’ Equity (Continued)

Warrants (continued)

The weighted average fair value of the warrants granted during the years ended December 31, 2007 and 2006 was $0.27 and $0.34, respectively. The fair value of common stock warrants granted is estimated at the date of grant using the Black-Scholes option pricing model by using the historical volatility of comparable public companies. The calculation also takes into account the common stock fair market value at the grant date, the exercise price, the expected life of the common stock warrant, the dividend yield and the risk-free interest rate. Following are the assumptions used during the years ending December 31:

	2007		2006

Risk free rate		3.07% - 4.92%		4.20% - 4.30%
Expected life		3-5 years		5 years
Volatility		36%		46%
Dividend yield		0%		0%

Stock options

Effective May 13, 2005, the Board of Directors approved the 2005 Incentive Plan (“the Plan”) whereby the Company may award stock options and restricted stock to its employees, Board of Directors, consultants and advisors. The Board of Directors originally authorized a maximum of 15,000,000 options to be made available for grant under the Plan. During December 2007, the Board of Directors approved the increase in the number of shares of common stock of the Company available under the Plan to 30,000,000.

During 2007 and 2006, the Company granted options to purchase 1,200,000 and 1,575,000 shares, respectively, 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 to directors in 2007 vested immediately on the grant date and all options granted to directors in 2006 vested one year from the grant date. During 2007 and 2006, the estimated fair value of these stock options was determined on the grant date using the Black-Scholes option pricing model and the Company recorded $471,900 and $820,600, respectively, as general and administrative expense to account for the vested options. With the adoption of SFAS No. 123(R) effective January 1, 2006, the Company offset the remaining unamortized deferred compensation balance of $201,600 at December 31, 2005 against additional paid-in capital.

On August 29, 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 his options to purchase 150,000 shares of the Company’s common stock for 250,000 shares of the Company’s common stock. The estimated fair value of the option to exchange was determined on the agreement date using the Black-Scholes option pricing model to be $102,500 and recorded as general and administrative expense.

In addition, during 2007 and 2006, the Company granted options to purchase 650,000 and 650,000 shares, respectively, of the Company’s common stock at an exercise price of $0.75 per share to employees for services provided. These options expire five or seven years from the date of grant. Of these options granted, 400,000 and 525,000 were 100% vested on the date of grant during 2007 and 2006, respectively, and 250,000 granted in 2007 vest within 90 days from the grant date, and 125,000 granted in 2006 vest one year from the grant date. The estimated fair value of these stock options was determined on the grant date using the Black-Scholes option pricing model to be $192,240 and $261,950, respectively, of which $192,240 and $211,575, was amortized to general and administrative expense during 2007 and 2006, respectively.

At December 31, 2007, 19,250,000 stock options were available under the Plan.

The aggregate intrinsic value of stock options outstanding and exercisable at December 31, 2007 is zero and there were no common stock options exercised during 2007 or 2006.

F-32

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 8 –

Stockholders’ Equity (Continued)

Stock options (continued)

The following is a summary of the stock option activity for the years ended December 31:

	2007				2006
	Number of Shares		Weighted Average Exercise Price		Number of Shares			Weighted Average Exercise Price

Outstanding, beginning of year		8,500,000	$	0.75		6,425,000		$	0.75

Granted		1,850,000		0.75		2,225,000			0.75
Exercised		–		–		–			–
Expired or cancelled		–		–		(150,000	)		0.75

Outstanding, end of year		10,350,000	$	0.75		8,500,000		$	0.75

Exercisable, end of year		10,350,000	$	0.75		7,975,000		$	0.75

The weighted average remaining contractual life of outstanding and exercisable stock options at December 31, 2007 is 5.9 years.

The weighted average fair value of options granted during the years ended December 31, 2007 and 2006 was $0.36 and $0.50, respectively. The fair value of common stock options granted is estimated at the date of grant using the Black-Scholes option pricing model by using the historical volatility of a comparable public company. The calculation also takes into account the common stock fair market value at the grant date, the exercise price, the expected life of the common stock option, the dividend yield and the risk-free interest rate. In addition, the Company estimates a forfeiture rate at the inception of the option grant based on historical data and adjusts this prospectively as new information regarding forfeitures becomes available. Following are the assumptions used during the years ending December 31:

	2007		2006

Risk free rate		4.23% - 4.92%		4.20% - 4.30%
Expected life		5-10 years		5-10 years
Volatility		38%		46%
Dividend yield		0%		0%

F-33

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 8 –

Stockholders’ Equity (Continued)

Stock options (continued)

The following is a summary of the non-vested stock option activity for the years ended December 31:

	2007					2006
	Number of Shares			Weighted Average Exercise Price		Number of Shares			Weighted Average Exercise Price

Non-vested, beginning of year		525,000		$	0.75		800,000		$	0.75

Granted		1,850,000			0.75		2,225,000			0.75
Vested		(2,375,000	)		0.75		(2,350,000	)		0.75
Expired or cancelled		–			–		(150,000	)		0.75

Non-vested , end of year		–		$	–		525,000		$	0.75

Note 9 –

Related Party Transactions

During 2007 and 2006, the Company sold common stock of the Company totaling 100,000 and 466,667 shares, respectively, at $0.75 per share to its Board of Directors or to members of their immediate family. The total proceeds received from the sale of these shares during 2007 and 2006 were $75,000 and $350,000, respectively. In 2007, as an incentive for these investments, these related parties also received 18,750 warrants to purchase shares of the Company’s common stock at an exercise price of $0.75.

In order to reduce the number of warrants outstanding during 2006, the Company offered warrant holders an option to exchange their warrants on a four for five basis. The Company issued 15,165,600 shares of common stock to related party warrant holders in exchange for approximately 18,957,000 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 exercises was $0.75 per share. The Company recorded approximately $9,200,000 as warrant inducement expense within other income (expense) to account for the excess fair value of the common stock over the original estimate of the fair value of the warrants.

At December 31, 2007 and 2006, the Company had notes payable in the amount of $6,411,025 and $4,350,000 (net of unamortized debt discount of $455,976 and $0, respectively) owed to related parties, respectively. Total borrowings from related parties during the years ended December 31, 2007 and 2006 were $1,582,333 and $3,969,472, respectively.

Total interest expense on notes payable, related parties, was $305,028 and $262,090 for 2007 and 2006, respectively. Total interest payments were $238,081 and $232,655 in 2007 and 2006, respectively. In addition to these notes payable, the related party note holders received warrants to purchase a total of 470,000 and 375,000 shares of the Company’s common stock at an exercise price of $0.75 per share during 2007 and 2006, respectively. In addition, one certain related party note holder received an 8.5% overriding royalty interest, as defined, in a well named McDermott Estate #5 located in Union Parish, Louisiana, in conjunction with a $266,667 loan in 2006.

During 2007 and 2006, related party note holders converted a total of $200,000 and $266,667, respectively, of principal and $2,126 and $7,364 of interest into 269,501 and 365,375 shares of common stock, respectively, at an exchange rate of one share for each $0.75 of principal and interest. As an incentive to convert these related parties were granted 50,000 warrants to purchase shares of common stock at $0.75 per share, expiring in five years from date of grant.

F-34

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 9 –

During 2007, the Company sold to an individual board member a 1% ORRI in the Days Creek oil and natural gas property and granted to this board member 30,000 warrants with an exercise price of $0.75 per share, generating total proceeds of $100,000.

In, 2007, the Company repurchased various working interests in three well bores in its South Belridge Field that it had sold to related party individuals in 2005. The purchase price consideration comprised offsetting $125,003 of net joint interest billings owed to the Company, the issuance of $1,250,000 of 9% convertible notes payable maturing in October 2009 (see Note 5), the issuance of 209,999 shares of common stock, and the granting of 562,500 warrants with an exercise price of $0.75 per share. The notes are convertible into common stock of the Company at a conversion rate of $0.75 per dollar of principal.

At December 31, 2007 and 2006, the Company had receivables of $51,154 and $112,846, respectively, due from directors, officers and employees and payables of $248,412 and $59,263, respectively, due to directors, officers and employees. These amounts are recorded in other accounts receivable and accounts payable, respectively. At December 31, 2006, the Company had receivables of $180,012 from related party well bore and revenue sharing agreement owners. At December 31, 2007, the Company had no receivable or payable from or due to these same related parties.

In addition to the transactions described above, the following table summarizes various transactions with several of the Company’s board of directors, officers, employees, and members of their immediate family during 2007 and 2006:

	Year Ended December 31, 2007
	Cash		Common Stock Options		Common Stock Warrants		Total

Consulting fees-board members	$	–	$	471,900	$	–	$	471,900
Consulting fees-officers and their immediate family		177,145		–		–		177,145
Commissions-employee		32,500		–		–		32,500
Rental expense-board member		2,100		–		–		2,100
Offering costs-board members and their immediate family		–		–		606,000		606,000
Note extension and conversion- board members and their immediate family		–		–		273,810		273,810

	$	211,745	$	471,900	$	879,810	$	1,563,455

	Year Ended December 31, 2006
	Cash		Common Stock Options		Common Stock		Total

Consulting fees-board members	$	306,000	$	923,100	$	–	$	1,229,100
Consulting fees-officers and their immediate family		37,000		–		–		37,000
Commissions-employee		200,000		–		–		200,000
Rental expense-board member		4,900		–		–		4,900
Finance costs-board member		12,000		–		–		12,000
Purchase of intellectual property- board member		250,000		–		750,000		1,000,000

	$	809,900	$	923,100	$	750,000	$	2,483,000

F-35

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 9 –

In the past, certain related parties have received RSAs and ORRIs in different transactions. The following table summaries the different types of revenue interests these related parties received and amounts they earned during 2007 and 2006 from those interests.

Plan	Interest			2007		2006

$4 M Net Distribution		28.00	%	$	35,746	$	45,151
SB & Belton Fields RSA		14.64	%		47,206		75,455
Marion Field RSA		1.20	%		–		845
McDermott Estate #5 ORRI		8.50	%		44,533		7,013
Days Creek Field ORRI		1.00	%		1,461		–

				$	128,946	$	128,464

Note 10 –

General and Administrative Expenses

General and administrative expenses consisted of the following for the years ended December 31:

	2007		2006

Payroll, payroll taxes, and related benefits	$	5,856,128	$	5,024,402
Consulting services		485,971		981,541
Commissions and marketing costs		337,500		200,000
Legal and professional		945,819		606,651
Travel and entertainment		293,206		783,537
Office and equipment lease		192,937		167,490
Insurance		154,932		123,728
Other expenses		377,925		269,876

Total	$	8,644,418	$	8,157,225

Note 11 –

Federal Income Tax

No provision for federal income taxes has been recognized for the years ended December 31, 2007 and 2006 as the Company incurred a net operating loss for income tax purposes in each year and has no carryback potential. Additionally, it is uncertain if the Company will have taxable income in the future so a valuation allowance has been established for the full value of net tax assets. Deferred tax assets and liabilities as of December 31, 2007 and 2006, consist of the following:

	2007		2006
Deferred tax assets:
Net operating loss carry forwards	$	27,133,235	$	16,438,924
Stock based compensation		1,394,023		1,168,216

Total deferred tax assets		28,527,258		17,607,140

F-36

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 11 –

Federal Income Tax (Continued)

	2007			2006
Deferred tax liabilities:
Basis difference in property and equipment		1,966,803			1,224,437
Other		8,271			9,357

Total deferred tax liabilities		1,975,074			1,233,794

Total deferred tax assets, net		26,552,184			16,373,346

Valuation allowance		(26,552,184	)		(16,373,346	)

Net deferred tax assets	$	–		$	–

The Company has provided a valuation allowance for net deferred tax assets, as it is more likely than not that these assets will not be realized. For the year ended December 31, 2007, the valuation allowance increased by $10,178,838.

At December 31, 2007, the Company has net operating loss carryforwards of approximately $79.8 million for federal income tax purposes. These net operating loss carryforwards may be carried forward in varying amounts until 2026 and may be limited in their use due to significant changes in the Company's ownership.

A reconciliation of the income tax provision computed at statutory tax rates to the income tax provision for the years ended December 31, 2007 and 2006 is as follows:

	2007			2006

Federal income tax expense (benefit) at statutory rate		(34	)%		(34	)%
Change in valuation allowance		34	%		34	%

Total income tax provision		–	%		–	%

Note 12 –

Commitments and Contingencies

Litigation

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

F-37

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 12 –

Commitments and Contingencies (Continued)

Litigation (continued)

Contingencies

During September 2007, the Company executed an agreement with a consulting services firm to provide investor relations services for a period of up to 24 months upon the Company going public on a publicly traded exchange. As consideration for their services, 4,599,692 shares of common stock are to be issued contingent on the Company becoming traded on a public listed exchange.

F-38

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2006

Note 12 –

Commitments and Contingencies (Continued)

Operating leases

The Company leases its office space under a long-term operating lease that expires in 2009. Total rent expense incurred for the years ended December 31, 2007 and 2006 was $187,740 and $141,233, respectively.

Future minimum lease payments for non-cancelable operating leases are as follows:

Year Ended December 31,

2008	$	143,756
2009		123,000

Total minimum lease payments	$	266,756

Note 13 –

Reporting by Business Segments

The Company has three operating segments: oil and natural gas exploration and production, drilling services and lateral drilling services. These segments are managed separately because of their distinctly different products, operating environments and capital expenditure requirements. The oil and natural gas production unit explores for, develops, produces and markets crude oil and natural gas, with all areas of operation in the United States. The drilling services unit provides drilling services for the Company’s subsidiaries and their working interest partners and to third parties. The lateral drilling services unit provides lateral drilling services for third parties, sub-licenses the Company’s LHD Technology, and sells related LHD Technology equipment. Segment performance is evaluated based on operating income (loss), which represents results of operations before considering general corporate expenses, interest and debt expenses, other income (expense) and income taxes.

F-39

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 13 –

Reporting by Business Segments (Continued)

	Year Ended December 31,
	2007			2006
Revenues:
Oil and natural gas exploration and production	$	3,536,231		$	2,979,219
Drilling services		329,018			66,344
Lateral drilling services		257,500			377,500
Total		4,122,749			3,423,063

Operating income (loss):
Oil and natural gas exploration and production		(11,863,510	)		(10,820,025	)
Drilling services		(813,690	)		(1,117,711	)
Lateral drilling services		(767,633	)		(576,381	)
Total		(13,444,833	)		(12,514,117	)

Corporate expenses (1)		(6,341,615	)		(5,791,412	)
Alternative investment market fund raising activities		–			(2,666,587	)
Impairment of investment		(1,365,712	)		(179,400	)
Warrant inducement expense		–			(10,934,480	)
Interest expense, net		(8,847,238	)		(4,468,373	)
Loss on extinguishment of debt		–			(234,630	)
Other miscellaneous income (expense), net		13,858			(33,510	)

Net loss	$	(29,985,540	)	$	(36,822,509	)

Depletion, depreciation and amortization:
Oil and natural gas exploration and production	$	1,894,779		$	1,347,137
Drilling services		7,287			30,148
Lateral drilling services		846,313			337,385
Other		50,379			45,731
Total	$	2,798,758		$	1,760,401

Impairment of oil and natural gas properties:	$	7,445,367		$	4,843,688

Capital expenditures (2):
Oil and natural gas exploration and production	$	2,205,524		$	16,807,126
Drilling services		–			1,866,392
Lateral drilling services		–			410,636
Other		17,404			77,015
Total	$	2,222,928		$	19,161,169

Total assets:
Oil and natural gas exploration and production	$	29,183,382		$	32,135,951
Drilling services		38,789			47,644
Lateral drilling services		5,085,550			6,204,684
Other		630,558			5,924,408
Total	$	34,938,279		$	44,312,687

	(1)	Includes non-cash charges for the fair value of stock options granted to employees and non-employee directors for services of $664,140 and $1,134,675 in 2007 and 2006, respectively.
	(2)	Includes capital expenditures for oil and natural gas properties, capital expenditures for property and equipment, change in oil and natural gas properties accrual, and purchase of intangible assets.

F-40

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 14 –

Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)

The following disclosures provide unaudited information required by SFAS No. 69, “Disclosures About Oil and Gas Producing Activities.”

Results of operations from oil and natural gas producing activities

The Company’s oil and natural gas properties are located within the United States. The Company currently has no operations in foreign jurisdictions.

Results of operations from oil and natural gas producing activities are summarized below for the years ended December 31:

	2007			2006

Revenues	$	3,536,231		$	2,979,219
Production (lifting) costs:
Production and lease operating expenses		2,992,812			1,725,211
Revenue sharing royalties		165,418			389,757
Exploration costs		458,650			882,884
Impairment of oil and natural gas properties		7,445,367			4,843,688
Accretion of asset retirement obligation		165,786			107,596
Depreciation, depletion and amortization		1,797,276			1,299,083

Total costs		13,025,309			9,248,219

Pretax income (loss) from producing activities		(9,489,078	)		(6,269,000	)
Income tax expense		–			–
Results of oil and natural gas producing activities (excluding overhead and interest costs)	$	(9,489,078	)	$	(6,269,000	)

Costs incurred

Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below for the years 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 obligations		330,299		890,355
Total costs incurred	$	12,766,134	$	20,445,798

F-41

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 14 –

Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited) (Continued)

Oil and natural gas reserves

Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods.

Proved oil and natural gas reserve quantities at December 31, 2007 and 2006, and the related discounted future net cash flows are based on estimates prepared by independent petroleum engineers. 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. The reserves as of December 31, 2006 were derived from reserve estimates prepared by Aluko & Associates, Inc., an independent reserve engineer. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission.

The Company’s net ownership interests in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized below as of December 31:

	Barrels of Oil and Condensate
	2007			2006

Proved developed and undeveloped reserves:
Beginning of year		2,464,821			82,289
Purchase of oil and natural gas property in place		6,048			2,435,779
Discoveries and extensions		587,336			–
Revisions		(20,343	)		(37,080	)
Sale of oil and natural gas properties in place		(389,687	)		–
Production		(23,880	)		(16,167	)

End of year		2,624,295			2,464,821

Proved developed reserves at beginning of year		665,751			29,211

Proved developed reserves at end of year		143,806			665,751

F-42

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 14 –

Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited) (Continued)

Oil and natural gas reserves (continued)

	Thousand Cubic Feet of Natural Gas
	2007			2006

Proved developed and undeveloped reserves:
Beginning of year		4,739,841			4,928,839
Purchase of oil and natural gas property in place		58,180			–
Discoveries and extensions		–			66,997
Revisions		(2,516,358	)		57,590
Sale of oil and natural gas properties in place		–			–
Production		(293,788	)		(313,585	)

End of year		1,987,875			4,739,841

Proved developed reserves at beginning of year		4,739,841			4,625,302

Proved developed reserves at end of year		1,987,875			4,739,841

Purchases of oil and gas property in 2007 related to the purchase of additional working interest in the South Belridge Field with 6,048 bbl of oil reserves and 55,990 Mcf of natural gas reserves. Purchases of oil and natural gas property in 2006 consist of the Days Creek Field with 26,795 bbl of oil reserves and the Delhi Field with 2,408,983 bbl of oil reserves. Discoveries and extensions in 2007 of 517,252 bbl of oil reserves were from new proved undeveloped reserves in the Days Creek Field’s reserve report. Remaining discoveries and extensions in 2007 were from newly drilled and producing wells, and extrapolated proved undeveloped wells in the Belton Field and Stephens Field. Discoveries and extensions in 2006 were from the newly drilled wells in the Marion Field. Revisions in 2007 consist of a 2,569,809 Mcf natural gas reserves reduction from unfavorable decline curve adjustments by the independent engineers in the Marion Field as improved production expectations from the prior year were not met. This unfavorable decline curve adjustment also significantly shortened the reserve reports economic life of this field, thereby further reducing proved reserves. Revisions in 2006 consist of favorable decline curve adjustments made by the independent engineers in the Marion Field, offset by two wells in South Belridge included as proved undeveloped in 2005 being developed in 2006 and producing less oil and natural gas than originally projected in the 2005 reserve report. Sales of oil and natural gas properties in place in 2007 related to the Company’s sale of its interest in the Holt Bryant Sand formation of the Delhi property (see Note 3). Production came from all fields in 2007. Production in 2006 includes a full year of the wells drilling in 2005 in the South Belridge Field and two more wells were put on production mid-year. Production in 2006 also includes natural gas production from the newly acquired Marion Field.

F-43

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 14 –

Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited) (Continued)

Standardized measure

The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved oil and natural gas reserves for the years ended December 31 are shown below:

	2007			2006

Future cash inflows	$	256,364,850		$	162,138,215
Future oil and natural gas operating expenses		(57,090,933	)		(47,342,964	)
Future development costs		(7,547,994	)		(4,144,583	)
Future income tax expenses		(29,301,076	)		(14,199,754	)
Future net cash flows		162,424,847			96,450,914
10% annual discount for estimating timing of cash flow		(73,586,774	)		(43,133,667	)
Standardized measure of discounted future net cash flow	$	88,838,073		$	53,317,247

Future cash flows are computed by applying year-end prices of oil and natural gas to year-end quantities of proved oil and natural gas reserves. Average prices used in computing year-end 2007 and 2006 future cash flows were $92.79 and $54.39 for oil, respectively, and $6.46 and $5.92 for natural gas, respectively. Future operating expenses and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved oil and natural gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

Future income taxes are based on year-end statutory rates, adjusted for tax basis of oil and natural gas properties and availability of applicable tax assets, such as net operating losses. A discount factor of 10% was used to reflect the timing of future net cash flows.

The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

Changes in standardized measure

Included within standardized measure is reserves purchased in place. The purchase of reserves in place includes undeveloped reserves which were acquired at minimal value that have been estimated by independent reserve engineers to be recoverable through existing wells utilizing equipment and operating methods available to the Company and that are expected to be developed in the near term based on an approved plan of development contingent on available capital.

F-44

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 14 –

Supplementary Financial Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited) (Continued)

Changes in standardized measure (continued)

Changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves for the years ended December 31 is summarized below:

	2007			2006

Changes due to current-year operations:
Sale of oil and natural gas, net of oil and nature gas operating expenses	$	(378,001	)	$	(864,251	)
Extensions and discoveries		28,994,114			169,566
Development costs incurred		3,704,171			6,846,278
Purchase of oil and gas properties		829,006			57,031,266
Changes due to revisions in standardized variables:
Prices and operating expenses		34,207,796			(8,648,444	)
Income taxes		(8,176,684	)		(7,849,504	)
Estimated future development costs		(5,967,100	)		(2,898,848	)
Revision of quantities		(11,025,750	)		(2,156,261	)
Sales of reserves in place		(5,549,976	)		–
Accretion of discount		6,116,675			1,327,927
Production rates, timing and other		(7,233,425	)		(2,919,752	)

Net of change		35,520,826			40,037,977

Beginning of year		53,317,247			13,279,270

End of year	$	88,838,073		$	53,317,247

Note 15 –

Subsequent Events

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, of which 10,000,000 has been designated as a Series A Preferred Stock, at a par value of $.00001 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.

F-45

Maxim TEP, Inc. and Subsidiaries

Notes to the Consolidated Financial Statements

December 31, 2007

Note 15 –

Subsequent Events (Continued)

The Company also converted $2,000,000 of convertible notes to Series A Preferred Stock which were originally issued in October 2007 to acquire various working interests in certain wells located in the South Belridge Field from several individuals, totaling $3,000,000. The Company is in negotiations to convert the remaining $1,000,000 notes and accrued interest of said debt.

During April 2008, the Company sold its South Belridge field, with a net book value of approximately $4.7 million 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 notes payable and approximately $6,100,000 in accrued interest. 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.

As of May 15, 2008, total proceeds of approximately $543,100 were generated through private offerings of approximately 724,132 shares of the Company’s common stock. The Company also granted 177,500 warrants to these investors with an exercise price of $0.75 per share as incentive to invest.

As of May 15, 2008, the Company borrowed an additional $400,000 from management and directors. The borrowing was subsequently converted into common stock at a price of $0.75 per share, or 533,333 shares. Additionally, $5,048,000 of convertible notes also converted, plus accrued interest of $51,841 at a price of $0.75 per share. for a total of 6,799,788 shares.

As of May 15, 2008, the Company sold 2% of ORRIs in the Days Creek Field and 7% of ORRIs in its Marion Field to investors generating total proceeds of $675,000. These ORRIs were subsequently converted into stock at $0.75 per share or 900,000 shares.

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 execution of the new 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.

In May 2008, two directors stepped down from the Board of Directors, both citing personal reasons. During the same period, the Company hired an experienced oil and gas executive as Director, President and COO of the Company.

F-46