Filed by Securities Law Institute EDGAR Services (888) 546-6454 - Petrol Oil & Gas

Equity compensation plans approved by stockholders

Equity compensation plans not approved by stockholders

2,390,000 (1)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

As of June 30, 2006, the aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates of the registrant was $34,803,925.25 based on the closing sale price of the registrant’s common stock on the over-the-counter securities market through the National Association of Securities Dealers Automated Quotation Bulletin Board System.

The number of shares of Common Stock, $0.001 par value, outstanding on April 9, 2007 was 29,090,926 shares.

This document contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact are “forward-looking statements” for purposes of federal and state securities laws, including, but not limited to, any projections of earnings, revenue or other financial items; any statements of the plans, strategies and objections of management for future operations; any statements concerning proposed new services or developments; any statements regarding future economic conditions or performance; any statements or belief; and any statements of assumptions underlying any of the foregoing.

Forward-looking statements may include the words “may,” “could,” “estimate,” “intend,” “continue,” “believe,” “expect” or “anticipate” or other similar words. These forward-looking statements present our estimates and assumptions only as of the date of this report. Except for our ongoing securities laws, we do not intend, and undertake no obligation, to update any forward-looking statement.

Although we believe that the expectations reflected in any of our forward-looking statements are reasonable, actual results could differ materially from those projected or assumed in any or our forward-looking statements. Our future financial condition and results of operations, as well as any forward-looking statements, are subject to change and inherent risks and uncertainties. The factors impacting these risks and uncertainties include, but are not limited to:

For a detailed description of these and other factors that could cause actual results to differ materially from those expressed in any forward-looking statement, please see Item 1A. Risk Factors in this document.

In this Form 10-K references to “PETROL”, “the Company”, “we,” “us,” and “our” refer to PETROL OIL AND GAS, INC. and its subsidiaries

Throughout this document we may use certain terms or phrases that are specific to the oil and gas industry. We have included a glossary containing these terms and phrases. We encourage you to refer to the glossary to gain a better understanding of industry terms used throughout this filing.

Petrol Oil and Gas, Inc. was incorporated in the State of Nevada in March of 2000 as Euro Technology Outfitters. On August 19, 2002 we acquired approximately 289 oil and gas mineral leases from Petrol Energy, and concurrently changed our name to Petrol Oil and Gas, Inc. Our common stock trades on the over-the-counter securities market through the National Association of Securities Dealers Automated Quotation Bulletin Board System, under the trading symbol “POIG”.

We are an oil and gas exploration, development and production company. Our properties are located in the Cherokee and Forrest City Basins along the Kansas and Missouri border. Our corporate strategy is to continue building value in the Company through the development and acquisition of gas and oil assets that exhibit consistent, predictable, and long-lived production. Our current focus is Coal Bed Methane reservoirs in the central U.S., which produce both Coal Bed Methane (“CBM”) and at times conventional gas.

We have consolidated a strong lease position in CBM that contains quality proven gas reserves, some of which are adjacent to interstate pipeline systems which provide ready access to sales markets for our produced gas. Beginning in 2005 our focus turned to developing and producing the company’s leases so as to realize the value held within their reserves. With approximately 165,000 gross leased acres (132,000 net acres) as of December 31, 2006 the task of developing the properties with wells on 160 acre spacing could involve emplacing in excess of 1,000 production wells. Petrol holds a 100 % working interest and an average 80% net revenue interest in these leases and Petrol is the operator of all of its producing properties.

During 2006, Petrol’s total gas production was approximately 1.038 Billion cubic feet (Bcf) (0.831 net to Petrol) as compared to 2005 when its gas production totaled approximately 0.969 Bcf (0.812 net to Petrol). This represents an increase of approximately 2.33% and is the result of implementing our 2005-2006 development plan. With a mix of daily gas pricing and fixed forward pricing contracts or hedges Petrol’s revenues rose to $6,532,798.

In order to develop this large resource base we have segregated our leases into five separate Projects which include:

The Coal Creek Project, centered in Coffey County, Kansas, includes leases covering about 92,000 gross acres. In October 2005 we finalized an agreement and other documents whereby Laurus Master Funds, Ltd. would provide a debt facility of up to $50,000,000 with the first $10,000,000 received in November 2005. In March 2006 we received the second installment of $5,000,000 and in May of 2006 we received the third installment of $10,000,000.

The Coal Creek development plan is based upon drilling and completing some 540 wells along with three gas gathering pipelines and gas processing systems. To better manage the development of this large acreage position and take advantage of the three interstate pipelines that cross our leases, we divided the project into three fully self contained areas:

The full development plan is expected to be executed in multiple phases. The pace of the development will obviously depend on the availability of the financing program, lender restrictions, general economic conditions, and potential other factors relevant to this type of development plan.

The first phase of our Coal Creek development plan included the drilling and completion of 32 production wells and 2 salt water disposal (SWD) wells in the Burlington area. These initial Phase 1 Burlington wells were incrementally connected to Petrol’s Coal Creek gas gathering, compressor and gas processing system as well as its salt water disposal system. Gas transport and sales, as well as testing and integration of these wells with the Enbridge Interstate pipeline began in April 2006.

Phase I development in the Waverly area began during the first quarter of 2006 and included drilling and completing 19 CBM production wells and 1 SWD well. By mid June, our new Waverly gas gathering pipeline system was integrated with these 19 production wells and our gas compressor station. Our field operations emplaced a second high pressure tap on the Enbridge Interstate Pipeline along with gas sales monitoring systems. By year end 2 new production wells were included in the Waverly area bringing the total to 21 production wells. All 21 Waverly production wells are in various stages of de-watering, as in Burlington.

During the second half of 2006 it became evident that water production rates from the producing coal seams in both Burlington and Waverly were higher than anticipated and thus two additional salt water disposal wells were drilled, one in Burlington and one in Waverly. In early October after receiving approval from the Kansas Corporation Commission to operate both new SWD’s they were integrated into the production system. The inclusion of these new SWD’s has almost doubled the available salt water disposal capacity in Burlington and Waverly.

To further our understanding of the water and gas production mechanisms from these multiple coal seams Petrol has concentrated its technical efforts on a cluster of 5-6 closely spaced wells in Burlington and Waverly. Our objective is to de-water these wells and the area around these wells as quickly and efficiently as possible thus exposing the gas bearing coal seams directly to the wellbore. The methodology being employed to attain that objective includes:

Although the data from these cluster wells is being analyzed it is clear that the permeability of the coal beds manifested by early water production is high and therefore desorbed gas should also be capable of flowing to the wellbore through the same permeable fracture or cleat system. CBM gas production although still relatively modest appears to show improvement as water pressure is reduce in the wellbore and as the coal beds and the fracture system de-water.

The entire Coal Creek development plan includes drilling and completing about 540 production wells and adding one more gas gathering pipeline and gas processing system to the existing two systems. The timing and the extent of the development will obviously depend on the availability of the financing program, the economic and technical conclusions based on the analysis of our testing program and favorable market conditions

Our gas producing leases known as Petrol-Neodesha, in the Neosho and Wilson counties, account for approximately 10,000 of the total 165,000 gross leased acres.

Gas production from Petrol-Neodesha during 2006 amounted to about 0.998 Bcf (0.793 Bcf net to Petrol) as compared to about 0.969 Bcf (0.770 Bcf net to Petrol) for 2005. This represents roughly a 2.95% increase year over year.

The Petrol-Neodesha project includes 104 CBM production wells, 8 SWD wells and a fully contained and integrated gas gathering pipeline and gas processing system. On average 101 of the 104 CBM producing wells are in active production. Our development plan is currently

being implemented that includes drilling additional wells, improving and re-completing existing wells and enhancing the gas gathering system. This plan was designed to serve as the blueprint to enhance the Net Asset Value of these properties, increase production revenue and provide knowledge for development of remaining leases in this and our other Project areas. These Petrol-Neodesha properties have provided us with the bulk of our revenue stream and value in proven producing reserves.

In the spring and summer of 2005 we implemented Phase I of our Neodesha development plan that involved expanding the production capacity of our existing gas gathering pipeline system and drilling several new production wells. Pipeline enhancements included adding approximately 3.5 miles of high capacity gas gathering pipeline and strategically incorporating 2 new booster stations to reduce pipeline pressure as well as to provide a higher level of compressor redundancy. In addition, the reduced pipeline pressure was designed to increase production from existing production wells and in fact overall field production was found to increase by about 425 Mcfd. Furthermore, the capacity of the main pipeline gathering lines was doubled and will serve to accommodate production from 50 to 100 new development and re-completion wells. We also incorporated a new gas processing unit into our Neodesha pipeline system to support growing gas sales and enhance gas quality.

The second element of the Phase I development plan involved drilling a series of new multi-zone CBM production wells throughout the year. Since January 1, 2006, Petrol has re-completed or drilled 17 new multi-zone production wells on its Petrol-Neodesha properties, with a 100% success rate. These new wells are connected to Petrol’s gas gathering pipeline and gas processing system for further transport of produced gas through the Southern Star Interstate pipeline to our sales market.

The Neodesha development plan involves implementing a program employing advanced stimulation methodologies and staged re-completion techniques. The program is designed to improve our overall understanding of the effectiveness of multi-zone stimulations and their ability to enhance production and reduce stimulation costs. Petrol is actively involved in executing the data acquisition portion of this plan. Petrol has employed outside consultants with expertise in fracture stimulation of un-conventional reservoirs such as CBM to support our efforts in this technical program.

Overall gas production in 2006 was an all time high amounting to about 0.998 Bcf. Based on our current field performance and production levels, we plan to aggressively develop future production activities and lease acquisitions in and around Petrol-Neodesha.

Located primarily in Franklin County, Kansas the Pomona Project includes leases covering about 35,000 acres. There are about 17 shut in production wells, a salt water disposal well and portions of a gas gathering infrastructure. Two interstate pipeline systems cross through our leases.

Because Petrol remains committed to first developing Petrol-Neodesha and Coal Creek, the development and lease renewal of this Pomona project has been deferred pending financing opportunities or interested developmental partners

Located in Cass and Bates Counties, Missouri, our Missouri Project includes leases covering about 15,000 gross acres. We drilled and tested 5 evaluation wells on our lease that abut or are in close proximity to an interstate pipeline system.

Currently Petrol’s Missouri leases amount to about 15,000 gross acres, however since Petrol has focused most of its resources in Petrol-Neodesha and the development of Coal Creek the development and lease renewal of these Missouri properties has been deferred pending financing opportunities or interested developmental partners.

Petrol holds a 100% working interest in several oil producing properties in eastern Kansas that produced approximately 22,249 barrels of oil (bbl) during 2006 (17,954 bbl net to Petrol). The oil producing wells on these properties and in the surrounding areas are generally defined as stripper wells and usually produce under the influence of a water flood.

Oil production from these wells is very dependent on weather conditions and the continuous injection of water in the water flood. As a consequence, production during winter months is often curtailed by cold weather particularly by freezing and during periods when rain fall is limited thereby reducing the amount of water that might be available for water flooding. As a consequence, monthly oil production varies considerably depending on the season and prevailing weather conditions.

Petrol continues to operate and improve these oil properties as efficiently and economically as possible. We employ contract pumpers to monitor and maintain production and local service companies to perform supportive maintenance on the wellbores and pumping equipment.

Although November and December of 2006 in eastern Kansas were not particularly plagued by continuous cold or freezing weather that changed significantly in Jan and Feb 2007 and the freezing weather tended to reduce production often by as much as 50%. These are not unusual circumstances for the Kansas plains and we expect production to increase as the milder spring weather approaches.

Petrol believes that the rising oil and gas prices, combined with geopolitical instability and soaring demand from burgeoning economies in China and India have increased the intrinsic value of predictable, secure, North American reserves, and we expect this trend to continue in light of tensions in the Middle East and certain other foreign countries (e.g., Venezuela, Nigeria).

The National Petroleum council estimates the US demand for natural gas to increase from 22 Trillion cubic feet (TCF) in 1998 to over 31 TCF by 2015. This nearly 50% increase in demand for natural gas coupled with constrained supplies from conventional sources and storage facilities suggests an urgent need for new gas sources. Although conventional gas sources such as high permeability sandstones supply about 60% of the US demand (13 TCF in 1998), projections indicate a flat to declining supply through year 2015. The shortfall in conventional gas supply is expected to be taken up by production from un-conventional sources such as tight gas sandstones/shales, associated gas, and CBM.

CBM shows great promise as a future source of natural gas, with the US Geological Survey estimating some 700 TCF contained in 6 major CBM basins in the continental US. This constitutes an enormous reserve, almost the entire US demand for the next 25 years. The Western Interior Basin covering portions of Oklahoma, Kansas, and Missouri is one of those 6 major basins. The Gas Research Institute estimates CBM gas reserves in the Forrest City and Cherokee basin, the two sub-basins of the Western Interior Basin, contain approximately 7 TCF. Petrol’s leases all lie within one or both of these sub-basins

Given the current volatility of the natural gas market, hedging has become a part of Petrol’s operating strategy. We believe the current supply and demand fundamentals will lead to a strengthening in prices. Consequently, Petrol intends to continually evaluate its hedge position, if any, and enter into contracts accordingly.

CBM production is similar to conventional natural gas production in terms of the physical production facilities and the product produced. However, surface mechanics and some production characteristics of CBM wells are quite different from traditional natural gas production wells. Methane gas is created as part of the coalification process. Coals vary in their methane gas content which is defined by the industry as cubic feet of gas per ton of coal. Conventional natural gas wells assume a porous and permeable reservoir, hydrocarbon migration and a natural structural or stratigraphic trap. However, CBM is trapped in the molecular structure of the coal itself until it is released by pressure changes, resulting from water removal from the coal-bed.

Water completely permeates coal-beds and the natural fracture system or cleats as they are normally referred. In good producing areas the cleats are pervasive throughout the coal-beds. CBM gas, principally methane, is adsorbed onto the grain surfaces of the coal. To produce CBM, the water must be drawn off first, lowering the pressure so that the methane gas will desorb from the coal thus allowing gas to flow from the coal into the de-watered cleats that act as high permeable conduits to the well bore, where gas can be produced at the well head. These cleats are assumed to have been formed during the coalification and uplifting processes. If cleat permeability is adequately developed it may allow commercial quantities of methane gas to be produced from the well. The qualities of productive CBM wells include coal quality, the content of natural gas per ton of coal, thickness of the coal-beds, reservoir pressure, existence of natural fractures, and overall permeability of the coal-bed.

CBM production also differs from conventional gas production that normally starts at its highest production rate and then declines with time. Because coal-beds have water residing within the cleats, the water needs to be withdrawn in order to promote production of the adsorbed gases. Thus, for the case of CBM, initial water production is high and diminishes with time. CBM gas production, however, starts at a relatively low rate reaching a peak some months later and then begins to decline.

CBM production is attractive due to several geological factors. Coal stores six or seven times as much gas as a conventional natural gas reservoir of equal rock volume due to the large internal surface area of coal. Significant amounts of coal are accessible at shallow depths, making well drilling and completion relatively inexpensive. Finding costs are also low since methane occurs in coal deposits, and the location of the Nation’s coal resources is well defined by the USGS.

Petrol’s primary business objective is to create value in the company through the production of economic quantities of natural gas from CBM and other producible intervals. In the 6 major US CBM basins, the coal-beds vary greatly in thickness, quality and gas content. They also range in depths from very near surface, less than 500 ft, to very deep, greater than 25,000 ft. The difficulty, risks and costs associated with extracting CBM from deep formations increases quite rapidly and nonlinearly with depth. Average depth for a well in the areas where Petrol holds leases range between 600 ft and 1,700 ft.

Petrol acquired leases in the Forrest City and Cherokee Basins because the leased area had the following attributes:

The Western Interior Province located in the mid-continent, where the Petrol leases are located, shows great promise because the sub-basins embody an extensive aerial distribution of shallow buried coal-beds, sizeable portions appear to contain large quantities of high quality natural gas and have several readily available interstate pipelines for sales and distribution. It appeared that an area well suited for Petrol’s Coal Creek Project was in and around Coffey County, Kansas, where gas bearing coals are contained within the Forrest City and Cherokee basins, sub-basins of the larger Western Interior basin.

Since portions of Petrol’s acquired mineral leases have existing oil or gas wells, some of them are being considered for re-completion in sandstones or other conventional type reservoirs and coal-beds that appear economically productive. These will add to our knowledge base and may provide financial support for anticipated expansion. This developmental strategy is exemplified in our Petrol-Neodesha project which produced approximately 0.998 Bcf during 2006 or about 0.794Bcf of net production to Petrol.

As of December 31, 2006, we have about 900 signed lease agreements totaling approximately 165,000 gross acres (137,000 net acres). These leases are contained within Coffey County, Kansas and the adjacent counties of Anderson, Osage, Lyon, Franklin, Woodson, Wilson and Neosho as well as Cass and Bates counties in western Missouri. In the event that we are successful in the development phase of our plan and find commercially producible gas or oil, we intend to lease additional available mineral rights to the extent that we believe such land will further our exploration and development activities and provide increased value to Petrol.

All of the mineral leases that Petrol has executed grant it the exclusive right to explore for and develop oil, gas and other hydrocarbons and minerals that may be produced from wells drilled on the leased property without any depth restrictions. Each lease also grants us rights of way to easements for laying pipelines and servicing or drilling other wells in the vicinity of the leased property.

Our lease agreements vary both in term and price per acre. Some of our leases are for 2 year periods at $2/acre with extensions for 3 additional years, others are for 3 year periods at $3/acre with extensions for 3 additional years, while others are for 5 years at $1/acre with extensions for 3 additional years, and finally others are for 5 years at $10/acre with extensions for 3 additional years.

Our leases are on a paid up basis. Petrol has agreed to pay each lessor a royalty equal to 12.5% of any oil, gas or other minerals that may be produced from wells drilled on their leased property. In the event of a shut-in well capable of producing oil or gas, we have agreed to pay the lessor a royalty per net mineral acre. All the lease agreements allow Petrol to hold the lease with production.

Petrol continually reviews its lease obligations to determine which leases it will not, or may not renew. As of the date of this filing, Petrol may not renew portions of its Coal Creek, Pomona or Missouri Project leases.

Under its leases, Petrol has the right to pool the leased property with other land owned or leased by it in the immediate vicinity for the production of oil or gas. With respect to shallow gas and associated hydrocarbons produced in conjunction therewith, we have the right to pool or unitize the leased properties into a development pool of a maximum of 3,000 acres if we have drilled at least 2 wells within the pooled unit no later than 1 year after the expiration of the primary term of the lease.

We have completed a standard due diligence process on our leased property, including obtaining a title or title insurance to confirm our rights to any oil, gas or other minerals produced pursuant to our leases. Our final interest in any oil, gas or other mineral that we produce may vary depending upon negotiations with the mineral owners, financers, if any, as well organizations that we may contract to perform drilling, completion and operating activities on our wells.

Petrol has rights to a 100% working interest in all of its leased acreage. A “working interest” is the operating interest that gives us, as the operator, the right to drill, produce and conduct operating activities on the property and a share of production. Petrol has a Net Revenue interest (NRI) between 79.5% and 84.375% on all leased acreage.

Until the acquisition of the Petrol-Neodesha, most of our capital expenditures were associated with the acquisition of oil and gas mineral leases, raising capital and administrative costs. Our strategy now shifts to that of realizing value from those expenditures through the drilling and production of our properties, starting in our proven reserve areas. We intend to continue to expand our lease base, as appropriate. The rate of development will be carefully designed to blend external financing with income from existing production and other sources.

To reduce our exposure to unfavorable changes in natural gas prices we utilize energy swaps in order to have a fixed-price contract. These contracts allow us to be able to predict with greater certainty the effective natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided under the contracts. However, we will not benefit from market prices that are higher than fixed prices in contracts for hedged production. If we are unable to provide the quantity that we have contracted for we will have to go to the open market to purchase the required amounts that we have contracted to provide.

In 2005, Petrol entered into contracts with Seminole Energy Services LLC to sell 60,000 mmbtu per month for the period of March 2005 to February 2006 at various fixed prices with the overall average price of $5.99. Additionally, Petrol had contracts with Virginia Power to sell certain of its gas production through March 2007 at various fixed prices with the overall average price of $8.13.

From April 2007 through March 2008 Petrol has agreed to sell approximately 30,500 mmbtu at an average sales price of $7.32. The remainder of Petrol’s gas sales will be at current market price.

Regulation of Oil and Natural Gas Production. Our oil and natural gas exploration, production and related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, some states in which we may operate require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry will most likely increase our cost of doing business and may affect our profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations.

Federal Regulation of Natural Gas. The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas transportation rates and service conditions, which may affect the marketing of natural gas produced by us, as well as the revenues that may be received by us for sales of such production. Since the mid-1980’s, FERC has issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B (“Order 636”), that have significantly altered the marketing and transportation of natural gas. Order 636 mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other components of the city-gate sales services such pipelines previously performed. One of FERC’s purposes in issuing the order was to increase competition within all phases of the natural gas industry. The United States Court of Appeals for the District of Columbia Circuit largely upheld Order 636 and the Supreme Court has declined to hear the appeal from that decision. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation service, and has substantially increased competition and volatility in natural gas markets.

The price we may receive from the sale of oil and natural gas liquids will be affected by the cost of transporting products to markets. Effective January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. We are not able to predict with certainty the effect, if any, of these regulations on our intended operations. However, the regulations may increase transportation costs or reduce well head prices for oil and natural gas liquids.

Our operations and properties subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may:

The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general.

The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring land owners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.

The Endangered Species Act (“ESA”) seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. ESA provides for criminal penalties for willful violations of the Act. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily

limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations will be in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject us to significant expenses to modify our operations or could force us to discontinue certain operations altogether.

We compete with numerous other oil and gas exploration companies. Many of these competitors have substantially greater resources than we do. Should a larger and better financed company decide to directly compete with us, and be successful in its competitive efforts, our business could be adversely affected.

We currently have eight full time employees and two part time employees as well as up to twelve contract personnel that support and operate our field operations. As drilling production activities increase, we intend to hire additional technical, operational and administrative personnel as appropriate. None of our employees are subject to any collective bargaining agreements; however, we have entered into an employment agreement with our CEO.

On August 7, 2006, we renewed our consulting agreement with CEOcast, Inc., wherein CEOcast agreed to provide us with investor relations services. The term of the agreement is for one year. We agreed to compensate CEOcast $7,500 upon signing the agreement and 60,000 shares of our common stock. In addition, we will pay CEOcast $7,500 on or before the 7^th day of each month during the term of the agreement. The 60,000 shares of common stock were issued to CEOcast on September 26, 2006.

On January 1, 2006, we entered into a consulting agreement with RJ Falkner & Company, Inc. for a period of one year. The consultant agreed to prepare two “Research Profile” reports and distribute such reports to over 10,000 investment professionals during the first twelve months of the agreement. We agreed to pay a retainer fee payable monthly, in advance, at a rate of $3,500 per month plus reimbursement of any expenses incurred in the provision of these services. In addition we agreed to grant the consultant a three year option to purchase 110,000 shares of our common stock at $1.76 per share.

Subsequent to year-end, our board of directors engaged the services of Duane Fadness, a current member of our board of directors, to assist in evaluating our field operations. Mr. Fadness will be paid $1,000 per day for services performed on our behalf along with being reimbursed for out of pocket costs and expenses.

Our proposed personnel structure could be divided into three broad categories: management and professional, administrative, and project field personnel. As in most small

companies, the divisions between these three categories are somewhat indistinct, as employees are engaged in various functions as projects and work loads demand.

Available Information. Our Internet website address is www.petroloilandgas.com. Information contained on our website is not part of this report on Form 10-K. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K filed with (or furnished to) the Securities and Exchange Commission (SEC) are available on our Internet website (in the “Investor Relations” section), free of charge, as soon as reasonably practicable after we file or furnish such material. Our governance documents are available in print to any stockholder that makes a written request to the Secretary of the Corporation at Corporate Woods, Building 51, 9393 West 110^th Street, Suite 500, Overland Park, Kansas 66210.

We have substantial indebtedness to Laurus Master Fund, Ltd. which is secured by all of our assets. If an event of default occurs under the secured notes issued to Laurus Funds, Laurus Funds may foreclose on all of our assets and we may be forced to curtail our operations or sell some or all of our assets to repay the notes.

On October 28, 2004, we entered into an $8,000,000 credit facility with Laurus Master Fund, Ltd. pursuant to a secured convertible term note and related agreements. On October 31, 2005, we entered into a $50 million credit facility with Laurus Master Fund, Ltd., pursuant to a secured note and related agreements whereby we received an initial $10,000,000. On March 31, 2006, we entered into agreements with Laurus Master Fund, Ltd. to draw down an additional $5,000,000 under the credit facility provided by Laurus on October 31, 2005. On May 31, 2006, we entered into agreements with Laurus Master Fund, Ltd. to draw down an additional $10,000,000 under the credit facility provided by Laurus on October 31, 2005. Subject to certain grace periods, the notes and agreements provide for the following events of default (among others):

In the event of a future default under our agreements with Laurus Funds, Laurus Funds may enforce its rights as a secured party and we may lose all or a portion of our assets or be forced to materially reduce our business activities.

The issuance of shares to Laurus Funds upon conversion of the convertible term note and exercise of its warrants may cause immediate and substantial dilution to our existing stockholders.

The issuance of shares upon conversion of the convertible term note and exercise of warrants may result in substantial dilution to the interests of other stockholders. Laurus Funds may ultimately convert and sell the full amount issuable on conversion. Although Laurus Funds in some cases may not, subject to certain exceptions, convert their term note and/or exercise their warrants if such conversion or exercise would cause them to own more than 4.99% of our outstanding common stock, this restriction does not prevent Laurus Funds from converting and/or exercising some of their holdings and then converting the rest of their holdings. In this way, Laurus Funds could sell more than this limit while never holding more than this limit, which will have the effect of further diluting the proportionate equity interest and voting power of holders of our common stock.

It is likely at the time shares of common stock are issued to Laurus Funds, the conversion price of such securities will be less than the market price of the securities. The issuance of common stock under the terms of our agreements with Laurus Funds will result in dilution of the interests of the existing holders of common stock at the time of the conversion. Furthermore, the sale of common stock owned by Laurus Funds as a result of the conversion of the convertible term note may result in lower prices for the common stock if there is insufficient buying interest in the markets at the time of conversion.

Laurus Funds has no obligation to convert shares if the market price is less than the conversion price.

Laurus has no obligation to cause us to issue common stock if the market price is less than the applicable conversion price ($1.50). In some of the days of the second and most of the third quarter our stock price was lower than the conversion discounted price granted to Laurus. Laurus has no obligation to convert the securities or to accept common stock as payment for interest if the market price of the securities for five trading days prior to a conversion date is less than 115% the conversion price. The amount of common stock that may be issued to Laurus is subject to certain limitations based on price, volume and/or the inventory of our common stock held by Laurus.

Because we face uncertainties in estimating proven recoverable natural gas reserves, you should not place undue reliance on such reserve information.

This Form 10-K contains estimates of natural gas reserves, and the future net cash flows attributable to those reserves, prepared by McCune Engineering, our independent petroleum and

geological engineer. There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control and the control of McCune Engineering. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to these reserves, is a function of the available data; assumptions regarding future natural gas and oil prices; expenditures for future development and exploitation activities; and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities and natural gas and oil prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from the assumptions and estimates in this Form 10-K. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classification of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in this Form 10-K were prepared by McCune Engineering in accordance with the rules of the SEC, and are not intended to represent the fair market value of such reserves.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs. However, actual future net cash flows from our natural gas and oil properties also will be affected by factors such as:

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

The SEC permits natural gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The SEC’s guidelines strictly prohibit us from including “probable reserves” and

“possible reserves” in filings with the SEC. We also caution you that the SEC views such “probable” and “possible” reserve estimates as inherently unreliable and these estimates may be seen as misleading to investors unless the reader is an expert in the natural gas industry. Unless you have such expertise, you should not place undo reliance on these estimates. Potential investors should also be aware that such “probable” and “possible” reserve estimates will not be contained in any “resale” or other registration statement filed by us that offers or sells shares on behalf of purchasers of our common stock and may have an impact on the valuation of the resale of the shares. We undertake no duty to update this information and does not intend to update the information.

Drilling wells is speculative, often involving significant costs that may be more than our estimates, and may not result in any addition to our production or reserves. Any material inaccuracies in drilling costs, estimates or underlying assumptions will materially affect our business.

Developing and exploring for natural gas and oil involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services. Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economic. Our initial drilling and development sites, and any potential additional sites that may be developed, require significant additional exploration and development, regulatory approval and commitments of resources prior to commercial development. Any success that we may have with these wells or any future drilling operations will most likely not be indicative of our current or future drilling success rate, particularly, because we intend to emphasize on exploratory drilling. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.

Development of our reserves, when established, may not occur as scheduled and the actual results may not be as anticipated. Drilling activity may result in downward adjustments in reserves or higher than anticipated costs. Our estimates will be based on various assumptions, including assumptions required by the Securities and Exchange Commission relating to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating our natural gas and oil reserves is anticipated to be extremely complex, and will require significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Due to our inexperience in the oil and gas industry, our estimates may not be reliable enough to allow us to be successful in our intended business operations. Our actual production, revenues, taxes, development expenditures and operating expenses will likely vary from those anticipated. These variances may be material.

Gas and Oil prices are volatile. This volatility may occur in the future, causing negative change in cash flows which may result in our inability to cover our capital expenditures.

Our future revenues, profitability, future growth and the carrying value of our properties is anticipated to depend substantially on the prices we may realize for our natural gas and oil production. Our realized prices may also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.

Natural gas and oil prices are subject to wide fluctuations in response to relatively minor changes in or perceptions regarding supply and demand. Historically, the markets for natural gas and oil have been volatile, and they are likely to continue to be volatile in the future. For example, natural gas and oil prices declined significantly in late 1998 and 1999 and, for an extended period of time, remained substantially below prices obtained in previous years. Among the factors that can cause this volatility are:

It is impossible to predict natural gas and oil price movements with certainty. Lower natural gas and oil prices may not only decrease our future revenues on a per unit basis but also may reduce the amount of natural gas and oil that we can produce economically. A substantial or extended decline in natural gas and oil prices may materially and adversely affect our future business enough to force us to cease our business operations. In addition, our financial condition, results of operations, liquidity and ability to finance planned capital expenditures will also suffer in such a price decline. Further, natural gas and oil prices do not necessarily move together.

We may incur substantial write-downs of the carrying value of our gas and oil properties, which would adversely impact our earnings.

We periodically review the carrying value of our gas and oil properties under the full cost accounting rules of the Securities and Exchange Commission. Under these rules, capitalized costs of proved gas and oil properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at an annual rate of 10%. Application of this “ceiling” test requires pricing future revenue at the un-escalated prices in effect as of the end of each fiscal quarter and requires a write-down for accounting purposes if the ceiling is exceeded, even if prices were depressed for only a short period of time. We may be required to write down the carrying value of our gas and oil properties when natural gas and oil prices are depressed or unusually volatile, which would result in a charge against our earnings. Once incurred, a write-down of the carrying value of our natural gas and oil properties is not reversible at a later date.

Currently the vast majority of our producing properties are located in the Cherokee Basin of southeastern Kansas, making us vulnerable to risks associated with having our production concentrated in one area.

The vast majority of our producing properties are geographically concentrated in the Cherokee Basin of southeastern Kansas. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters, adverse weather conditions or interruption of transportation of natural gas produced from the wells in this basin or other events which impact this area.

Competition in our industry is intense. We are very small and have an extremely limited operating history as compared to the vast majority of our competitors, and we may not be able to compete effectively.

We intend to compete with major and independent natural gas and oil companies for property acquisitions. We will also compete for the equipment and labor required to operate and to develop natural gas and oil properties. The majority of our anticipated competitors have substantially greater financial and other resources than we do. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for natural gas and oil properties and may be able to define, evaluate, bid for and acquire a greater number of properties than we can. Our ability to acquire additional properties and develop new and existing properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, some of our competitors have been operating in our core areas for a much longer time than we have and have demonstrated the ability to operate through industry cycles.

The natural gas and oil business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our development, exploitation and exploration activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas and oil well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves.

The natural gas and oil business involves a variety of operating risks, including:

If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:

Because we intend to use third-party drilling contractors to drill our wells, we may not realize the full benefit of worker compensation laws in dealing with their employees. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could impact our operations enough to force us to cease our operations.

The high cost of drilling rigs, equipment, supplies, personnel and other services could adversely affect our ability to execute on a timely basis our development, exploitation and exploration plans within our budget.

Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or interrupt our operations, which could impact our financial condition and results of operations. Drilling activity in the geographic areas in which we conduct drilling activities may increase, which would lead to increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. Increased drilling activity in these areas may also decrease the availability of rigs. We do not have any contracts with providers of drilling rigs and we cannot assure you that drilling rigs will be readily available when we need them. Drilling and other costs may increase further and necessary equipment and services may not be available to us at economical prices.

Our lease ownership may be diluted due to financing strategies we may employ in the future due to our lack of capital or due to our focus on producing leases.

To accelerate our development efforts we plan to take on working interest partners that will contribute to the costs of drilling and completion and then share in revenues derived from production. In addition, we may in the future, due to a lack of capital or other strategic reasons, establish joint venture partnerships or farm out all or part of our development efforts. These economic strategies may have a dilutive effect on our lease ownership and will more than likely reduce our operating revenues.

In addition, our lease ownership is subject to forfeiture in the event we are unwilling or unable to continue making lease payments. Our leases vary in price per acre and on the term period of the lease. Each lease requires payment to maintain an active lease. In the event we are unable or unwilling to make our lease payments or renew expiring leases, then we will forfeit our rights to such leases. Such forfeiture would prevent us from pursuing development activity on the leased property and could have a substantial impact on our gross leased acreage.

We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.

Development, production and sale of natural gas and oil in the United States are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:

Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations enough to possibly force us to cease our business operations.

Any leakage of crude oil and/or gas from the subsurface portions of our wells, our gathering system or our storage facilities could cause degradation of fresh groundwater resources, as well as surface damage, potentially resulting in suspension of operation of the wells, fines and penalties from governmental agencies, expenditures for remediation of the affected resource, and liabilities to third parties for property damages and personal injuries. In addition, any sale of residual crude oil collected as part of the drilling and recovery process could impose liability on us if the entity to which the oil was transferred fails to manage the material in accordance with applicable environmental health and safety laws.

Our auditor’s report reflects the fact that without realization of additional capital, it would be unlikely for us to continue as a going concern.

As a result of our deficiency in working capital at December 31, 2006 and other factors, our auditors have included an explanatory paragraph in their audit report regarding substantial doubt about our ability to continue as a going concern. The financial statements do not include any adjustments as a result of this uncertainty. The going concern qualification may adversely impact our ability to raise the capital necessary for the expansion and continuation of operations.

Our internal controls may be inadequate, which could cause our financial reporting to be unreliable and lead to misinformation being disseminated to the public.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. As defined in Exchange Act Rule 13a-15(f), internal control over financial reporting is a process designed by, or under the supervision of, the principal executive and principal financial officer and effected by the board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of Petrol; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of Petrol are being made only in accordance with authorizations of management and directors of Petrol, and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Petrol’s assets that could have a material effect on the financial statements.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. We cannot be certain that our efforts to maintain internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Further, we have a limited number of personnel that are required to perform various roles and duties as well as be

responsible for monitoring and ensuring compliance with our internal control procedures. As a result, our internal controls may be inadequate or ineffective, which could cause our financial reporting to be unreliable and lead to misinformation being disseminated to the public. Any failure to develop or maintain effective internal controls or difficulties encountered in implementing or improving our internal controls could harm operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls also could cause our stockholders and potential investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock. In addition, investors relying upon this misinformation may make an uninformed investment decision.

We may need additional capital in the future to finance our planned growth, which we may not be able to raise or it may only be available on terms unfavorable to us or our stockholders, which may result in our inability to fund our working capital requirements and harm our operational results.

We have had substantial capital expenditure and working capital needs associated with the development of our Coal Creek Project. We believe that current cash on hand and the other sources of liquidity are only sufficient enough to fund our operations through fiscal 2007. After that time we will need to rely on cash flow operations or raise additional cash to fund our operations, to fund our anticipated reserve replacement needs and implement our growth strategy, or to respond to competitive pressures and/or perceived opportunities, such as investment, acquisition, exploration and development activities.

If low natural gas and oil prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues or cash flows from operations to decrease, we may be limited in our ability to spend the capital necessary to complete our development, production exploitation and exploration programs. If our resources or cash flows do not satisfy our operational needs, we will require additional financing, in addition to anticipated cash generated from our operations, to fund our planned growth. Additional financing might not be available on terms favorable to us, or at all. If adequate funds were not available or were not available on acceptable terms, our ability to fund our operations, take advantage of unanticipated opportunities, develop or enhance our business or otherwise respond to competitive pressures would be significantly limited. In such a capital restricted situation, we may curtail our acquisition, drilling, development, and exploration activities or be forced to sell some of our assets on an untimely or unfavorable basis.

If we raise additional funds through the issuance of equity or convertible debt securities, the percentage ownership of our stockholders would be reduced, and these newly issued securities might have rights, preferences or privileges senior to those of existing stockholders.

We currently employ only one executive officer. The loss of this officer, whose knowledge and technical expertise upon which we rely, may harm our ability to execute our business plan.

Our success depends heavily upon the continued contributions of our sole executive officer, whose knowledge and technical expertise may be difficult to replace, and on our ability to retain and attract experienced engineers, geoscientists and other technical and professional

staff. We have entered into an employment agreement with this officer. If we were to lose his services, our ability to execute our business plan may be harmed and we may be forced to cease or limit our operations until such time as we could hire a suitable replacement for this officer.

Shortages of natural gas and oil field service personnel and equipment could adversely affect our business.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Due to recent high natural gas and oil prices, we have experienced shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled. Higher natural gas and oil prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services and personnel in our exploration and production operations. These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted.

If we fail to remain current on our reporting requirements, we could be removed from the OTC Bulletin Board which would limit the ability of broker-dealers to sell our securities and the ability of stockholders to sell their securities in the secondary market.

Companies trading on the OTC Bulletin Board, such as us, must be reporting issuers under Section 12 of the Securities Exchange Act of 1934, as amended, and must be current in their reports under Section 13, in order to maintain price quotation privileges on the OTC Bulletin Board. More specifically, NASD has enacted Rule 6530, which determines eligibility of issuers quoted on the OTC Bulletin Board by requiring an issuer to be current in its filings with the Commission. Pursuant to Rule 6530(e), if we file our reports late with the Commission three times in a two-year period or our securities are removed from the OTC Bulletin Board for failure to timely file twice in a two-year period then we will be ineligible for quotation on the OTC Bulletin Board. As a result, the market liquidity for our securities could be severely adversely affected by limiting the ability of broker-dealers to sell our securities and the ability of stockholders to sell their securities in the secondary market.

Because our common stock is deemed a low-priced “Penny” stock, an investment in our common stock should be considered high risk and subject to marketability restrictions.

Since our common stock is a penny stock, as defined in Rule 3a51-1 under the Securities Exchange Act, it will be more difficult for investors to liquidate their investment even if and when a market develops for the common stock. Until the trading price of the common stock rises above $5.00 per share, if ever, trading in the common stock is subject to the penny stock rules of the Securities Exchange Act specified in rules 15g-1 through 15g-10. Those rules require broker-dealers, before effecting transactions in any penny stock, to:

Consequently, the penny stock rules may restrict the ability or willingness of broker-dealers to sell the common stock and may affect the ability of holders to sell their common stock in the secondary market and the price at which such holders can sell any such securities. These additional procedures could also limit our ability to raise additional capital in the future.

NASD sales practice requirements may also limit a stockholder’s ability to buy and sell our stock.

In addition to the “penny stock” rules described above, the National Association of Securities Dealers (NASD) has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, the NASD believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. The NASD requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.

We could be subject to class action litigation due to stock price volatility, which, if occurs, could result in substantial costs or large judgments against us.

The market for our common stock may experience extreme price and volume fluctuations, which may be unrelated or disproportionate to our operating performance or prospects. In the past, securities class action litigation has often been brought against companies following periods of volatility in the market prices of their securities. We may be the target of similar litigation in the future. Securities litigation could result in substantial costs and divert our management’s attention and resources, which could have a negative effect on our business, operating results and financial condition.

As an equity interest, our common stock will not be secured by any of our assets. Therefore, in the event of our liquidation, the holders of the common stock will receive a distribution only after all of our secured and unsecured creditors have been paid in full. There

can be no assurance that we will have sufficient assets after paying our secured and unsecured creditors to make any distribution to the holders of the common stock.

Our Articles of Incorporation authorizes our Board of Directors to issue up to 10,000,000 shares of preferred stock, which could adversely affect the voting power of our common stock holders.

Our Board of Directors is authorized, without further approval of our stockholders, to fix the dividend rights and terms, conversion rights, voting rights, redemption rights and terms, liquidation preferences, and any other rights, preferences, privileges and restrictions applicable to our preferred stock. The issuance of such stock could adversely affect the voting power of the holders of Common Stock and, under certain circumstances, make it more difficult for a third party to gain control of Petrol, discourage bids for the common stock at a premium, or otherwise adversely affect the market price of the common stock.

Provisions in Nevada law could delay or prevent a change in control, even if that change would be beneficial to our stockholders.

Certain provisions of Nevada law may delay, discourage, prevent or render more difficult an attempt to obtain control of Petrol, whether through a tender offer, business combination, proxy contest or otherwise. The provisions of Nevada law are designed to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of Petrol to first negotiate with our board of directors.

The Nevada Revised Statutes (the “NRS”) contain two provisions, described below as “Combination Provisions” and the “Control Share Act,” that may make more difficult the accomplishment of unsolicited or hostile attempts to acquire control of Petrol through certain types of transactions.

Restrictions on Certain Combinations Between Nevada Resident Corporations and Interested Stockholders. The NRS includes the Combination Provisions prohibiting certain “combinations” (generally defined to include certain mergers, disposition of assets transactions, and share issuance or transfer transactions) between a resident domestic corporation and an “interested stockholder” (generally defined to be the beneficial owner of 10% or more of the voting power of the outstanding shares of the corporation), except those combinations which are approved by the board of directors before the interested stockholder first obtained a 10% interest in the corporation’s stock. There are additional exceptions to the prohibition, which apply to combinations if they occur more than three years after the interested stockholder’s date of acquiring shares. The Combination Provisions apply unless the corporation elects against their application in its original articles of incorporation or an amendment thereto. Our articles of incorporation do not currently contain a provision rendering the Combination Provisions inapplicable.

Nevada Control Share Act. Nevada’s Control Share Act imposes procedural hurdles on and curtails greenmail practices of corporate raiders. The Control Share Act temporarily disenfranchises the voting power of “control shares” of a person or group (“Acquiring Person”)

purchasing a “controlling interest” in an “issuing corporation” (as defined in the NRS) not opting out of the Control Share Act. In this regard, the Control Share Act will apply to an “issuing corporation”, unless the articles of incorporation or bylaws in effect on the tenth day following the acquisition of a controlling interest provide that it is inapplicable. Our articles of incorporation and bylaws do not currently contain a provision rendering the Control Share Act inapplicable.

Under the Control Share Act, an “issuing corporation” is a corporation organized in Nevada which has 200 or more stockholders of record, at least 100 of whom have addresses in that state appearing on the company’s stock ledger, and which does business in Nevada directly or through an affiliated company. Our status at the time of the occurrence of a transaction governed by the Control Share Act (assuming that our articles of incorporation or bylaws have not theretofore been amended to include an opting out provision) would determine whether the Control Share Act is applicable. We currently conduct business in Nevada through an executive office located in Las Vegas, Nevada.

The Control Share Act requires an Acquiring Person to take certain procedural steps before he or it can obtain the full voting power of the control shares. “Control shares” are the shares of a corporation (1) acquired or offered to be acquired which will enable the Acquiring Person to own a “controlling interest,” and (2) acquired within 90 days immediately preceding that date. A “controlling interest” is defined as the ownership of shares which would enable the Acquiring Person to exercise certain graduated amounts (beginning with one-fifth) of all voting power of the corporation in the election of directors. The Acquiring Person may not vote any control shares without first obtaining approval from the stockholders not characterized as “interested stockholders” (as defined below).

To obtain voting rights in control shares, the Acquiring Person must file a statement at the principal office of the issuer (“Offeror’s Statement”) setting forth certain information about the acquisition or intended acquisition of stock. The Offeror’s Statement may also request a special meeting of stockholders to determine the voting rights to be accorded to the Acquiring Person. A special stockholders’ meeting must then be held at the Acquiring Person’s expense within 30 to 50 days after the Offeror’s Statement is filed. If a special meeting is not requested by the Acquiring Person, the matter will be addressed at the next regular or special meeting of stockholders.

At the special or annual meeting at which the issue of voting rights of control shares will be addressed, “interested stockholders” may not vote on the question of granting voting rights to control the corporation or its parent unless the articles of incorporation of the issuing corporation provide otherwise. Our articles of incorporation and bylaws do not currently contain a provision allowing for such voting power.

If full voting power is granted to the Acquiring Person by the disinterested stockholders, and the Acquiring Person has acquired control shares with a majority or more of the voting power, then (unless otherwise provided in the articles of incorporation or bylaws in effect on the tenth day following the acquisition of a controlling interest) all stockholders of record, other than the Acquiring Person, who have not voted in favor of authorizing voting rights for the control

shares, must be sent a notice advising them of the fact and of their right to receive “fair value” for their shares. Our articles of incorporation and bylaws do not provide otherwise. By the date set in the dissenter’s notice, which may not be less than 30 nor more than 60 days after the dissenter’s notice is delivered, any such stockholder may demand to receive from the corporation the “fair value” for all or part of his shares. “Fair value” is defined in the Control Share Act as “not less than the highest price per share paid by the Acquiring Person in an acquisition.”

The Control Share Act permits a corporation to redeem the control shares in the following two instances, if so provided in the articles of incorporation or bylaws of the corporation in effect on the tenth day following the acquisition of a controlling interest: (1) if the Acquiring Person fails to deliver the Offeror’s Statement to the corporation within 10 days after the Acquiring Person’s acquisition of the control shares; or (2) an Offeror’s Statement is delivered, but the control shares are not accorded full voting rights by the stockholders. Our articles of incorporation and bylaws do not address this matter.

By the end of fiscal 2004, Petrol had built a solid asset base of mineral leases in SE Kansas and Missouri. In October 2005, Petrol acquired funding to purchase a 10,000 acre fully operational gas producing property we called Petrol-Neodesha. During 2005 we modified and enhanced the capacity of the Petrol-Neodesha gas gathering pipeline system to accommodate the full development of the property. In addition in 2005, we planned the development of our largest project area Coal Creek and began seeking financing to implement the planned development. In October 2005, we completed a financial agreement with Laurus Master Funds to begin developing Coal Creek. By late summer 2006, Petrol had developed two areas within Coal Creek with production wells, SWD wells and gas gathering pipelines and gas processing systems.

Although our focus will be on development of these existing properties, we also intend to continue seeking acquisition opportunities which compliment our current portfolio of producing and development properties. We intend to fund our development activity primarily through use of cash flow from operations and cash on hand, while pursuing substantial additional debt financing to fully develop our lease holdings and producing acquisitions.

As of December 31, 2006, we had estimated net reserves and future net income of:

On November 1, 2004, Petrol purchased producing mineral leases covering lands in Neosho and Wilson Counties, Kansas, that included 72 producing gas wells, SWD wells and a gas gathering system. The total purchase price was $10,000,000. Funding was accomplished using funds received from a unit offering and a convertible note from Laurus Master Fund. The producing property was named Petrol-Neodesha.

During 2005 Petrol modified and enhanced the capacity of the Petrol-Neodesha gas gathering pipeline system to accommodate the full development of the property and began drilling and completing new production wells. In 2006, Petrol drilled or re-completed 17 production wells in Petrol-Neodesha with a 100% success rate. All these new wells have been connected to our gas gathering pipeline system.

Petrol-Neodesha covers about 10,000 gross mineral acres (7,620 net acres) and currently includes approximately 104 production gas wells, 8 water disposal wells, about 70 miles of gas gathering pipelines and water lines as well as multiple gas compressor sites and a fully equipped operations and maintenance shop. 2006 cumulative gas production from Petrol-Neodesha amounted to about 0.998 Bcf (0.793 Bcf net to Petrol) for about a 2.95% increase over year end 2005.

Based on our current field production levels, we plan to aggressively develop future production activities in Petrol-Neodesha.

The Coal Creek Project, centered in Coffey County, Kansas, includes leases covering about 92,000 gross acres. In October 2005, we finalized an agreement and other documents whereby Laurus Master Funds, Ltd. would provide a debt facility of up to $50,000,000 for the development of Coal Creek.

Development of the Coal Creek plan accelerated in 2006 and the project area currently includes 51 production wells, 5 salt water disposal wells and two fully operational gas gathering pipelines and gas processing systems. Most of the production wells have been connected to the gas gathering systems and water disposal system in order to de-water the coals and promote gas production. Water production rates from the producing coal seams were substantially higher than anticipated and thus additional salt water disposal were drilled, one in Burlington and one in Waverly.

In late 2006 Petrol initiated a comprehensive testing and production analysis program in involving a set of cluster wells and is described in the Business section of this document. Although the data being derived from this from this testing and production analysis program is still being analyzed it is clear that the permeability of the coal beds manifested by early water production is high and gas rates although still modest appear to improve as the coal beds and the fracture system de-water.

In 2004 Petrol began evaluating CBM resources through the purchase of some mineral leases in NW Missouri. Petrol drilled and tested five (5) exploratory wells in Cass and Bates County, Missouri and based on that data began acquiring leases in the area which currently amounts to about 15,000 gross acres.

Petrol has focused its efforts and financing on its gas producing property in Petrol-Neodesha and the development of Coal Creek and thus the development and lease renewal of this Missouri property has been deferred pending financing opportunities or interested developmental partners.

In 2004 Petrol acquired mineral leases amounting to about 35,000 gross acres from CBM Energy Inc., which we called our Pomona project. The acquisition included 17 wells, several miles of gas gathering and water disposal pipelines, and a salt water disposal well. The Pomona project leases are located in Douglas, Franklin and Osage counties, Kansas.

Petrol remains committed to first developing Petrol-Neodesha and Coal Creek and thus the development and lease renewal of this Pomona project has been deferred pending financing opportunities or interested developmental partners.

The following table shows the results of operations from our oil and gas producing activities during the years presented in the financial statements. Results of operations from these activities have been determined using historical revenues, production costs, depreciation, depletion and amortization of the capitalized costs subject to amortization. General and administrative expenses and interest expense have been excluded from this determination.

In April 2006 we relocated our principal executive offices to Kansas. The address is Corporate Woods, Building 51, 9393 West 110^th Street, Suite 500, Overland Park, Kansas 66210. We executed a one year lease for 150 square feet. The monthly rental for the space is approximately $1,300.

We still maintain an executive office at 3161 E. Warm Springs Road, Suite 300, Las Vegas, Nevada 89120. The space consists of approximately 1,864 square feet, which houses administrative and executive offices. The monthly rental for the space is $3,450 per month (increasing by the consumer price index as defined in the lease with minimum annual increase of 3%) commencing April 15, 2004 and ending June 30, 2007 with the first three months free.

We also lease approximately 2,500 square feet of space in Waverly, Kansas, where our field and leasing offices are located. This facility is leased on a month-to-month basis with our monthly lease obligation being $300.

Petrol is and may become involved in various routine legal proceedings incidental to its business. However, to Petrol’s knowledge as of the date of this report, there are no material pending legal proceedings to which Petrol is a party or to which any of its property is subject.

Petrol did not submit any matters to vote of our stockholders during the fourth quarter of 2006.

Since March 4, 2004, we have been eligible to participate in the over-the-counter securities market through the National Association of Securities Dealers Automated Quotation Bulletin Board System, under the trading symbol “POIG”. The following table sets forth the quarterly high and low bid prices for our Common Stock during our last two fiscal years, as reported by a Quarterly Trade and Quote Summary Report of the OTC Bulletin Board. The quotations reflect inter-dealer prices, without retail mark-up, markdown or commission, and may not necessarily represent actual transactions.

As of April 9, 2007, we had approximately 90 stockholders of record of the 29,090,926 shares outstanding. As of April 9, 2007, the closing price of our shares of common stock was $0.44 per share.

We have never declared or paid dividends on our Common Stock. We intend to follow a policy of retaining earnings, if any, to finance the growth of the business and do not anticipate paying any cash dividends in the foreseeable future. The declaration and payment of future dividends on the Common Stock will be the sole discretion of the Board of Directors and will depend on our profitability and financial condition, capital requirements, statutory and contractual restrictions, future prospects and other factors deemed relevant.

Effective December 16, 2002, we adopted a 2002/2003 Stock Option Plan. The maximum number of shares that may be issued pursuant to the plan is 3,000,000 shares. As of December 31, 2006, all 3,000,000 options have been granted under this plan.

Effective December 21, 2005, we adopted a 2006 Stock Option Plan. The maximum number of shares that may be issued pursuant to the plan is 3,000,000 shares. As of December 31, 2006, 610,000 options have been granted under this plan.

Officers (including officers who are members of the board of directors), directors (other than members of the stock option committee to be established to administer the stock option plans) and other employees and consultants and its subsidiaries (if established) will be eligible to receive options under the stock option plans. The committee will administer the stock option plans and will determine those persons to whom options will be granted, the number of options to be granted, the provisions applicable to each grant and the time periods during which the options may be exercised. No options may be granted more than ten years after the date of the adoption of the stock option plans.

Non-qualified stock options will be granted by the committee with an option price equal to the fair market value of the shares of common stock to which the non-qualified stock option relates on the date of grant. The committee may, in its discretion, determine to price the non-qualified option at a different price. In no event may the option price with respect to an incentive stock option granted under the stock option plans be less than the fair market value of such common stock to which the incentive stock option relates on the date the incentive stock option is granted.

Each option granted under the stock option plans will be exercisable for a term of not more than ten years after the date of grant. Certain other restrictions will apply in connection with the plans when some awards may be exercised. In the event of a change of control (as defined in the stock option plans), the date on which all options outstanding under the stock option plans may first be exercised will be accelerated. Generally, all options terminate 90 days after a change of control.

The following table sets forth information as of December 31, 2006 regarding outstanding options granted under the plans, warrants issued to consultants and options reserved for future grant under the plan.

These plans are intended to encourage directors, officers, employees and consultants to acquire ownership of common stock. The opportunity so provided is intended to foster in participants a strong incentive to put forth maximum effort for its continued success and growth, to aid in retaining individuals who put forth such effort, and to assist in attracting the best available individuals to the Company in the future. As of December 31, 2006, no shares remained available for issuance under the 2002/2003 stock option plan and 2,390,000 shares remained available for issuance under the 2006 stock option plan.

The following chart compares the subsequent value of $100 invested in Petrol’s Common Stock for the period from March 8, 2004, the date Petrol’s Common Stock began trading on the OTC:BB, through December 31, 2006 to Petrol’s SIC code index and to the Russell 3000 index. The graph assumes the reinvestment of all dividends. The graph shows the value of the investment at the end of each year.

Petrol did not repurchase any of its equity securities during the years ended December 31, 2006 or 2005.

On October 26, 2006, we issued 10,127 shares of our restricted common stock to ECON Investor Relations, Inc., pursuant to its consulting agreement dated June 15, 2004. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2). The recipient of the shares was afforded an opportunity for effective access to files and records of Petrol that contained the relevant information needed to make its investment decision, including Petrol’s financial statements and 34 Act reports. We reasonably believe that the recipient, immediately prior to issuing the shares, had such knowledge and experience in its financial and business matters that it was capable of evaluating the merits mad risks of its investment. The recipient had the opportunity to speak with our president and directors on several occasions prior to its investment decision.

On December 19, 2006, we issued 50,000 shares of our restricted common stock to Lyons Capital, LLC, pursuant to its investor relations agreement dated August 14, 2006. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2). The recipient of the shares was afforded an opportunity for effective access to files and records of Petrol that contained the relevant information needed to make its investment decision, including Petrol’s financial statements and 34 Act reports. We reasonably believe that the recipient, immediately prior to issuing the shares, had such knowledge and experience in its financial and business matters that it was capable of evaluating the merits mad risks of its investment. The recipient had the opportunity to speak with our president and directors on several occasions prior to its investment decision.

On January 30, 2007, we issued 6,329 shares of our restricted common stock to ECON Investor Relations, Inc., as final payment for the services performed pursuant to its consulting agreement dated June 15, 2004. We believe that the issuance of the shares was exempt from the registration and prospectus delivery requirements of the Securities Act of 1933 by virtue of Section 4(2). The recipient of the shares was afforded an opportunity for effective access to files and records of Petrol that contained the relevant information needed to make its investment decision, including Petrol’s financial statements and 34 Act reports. We reasonably believe that the recipient, immediately prior to issuing the shares, had such knowledge and experience in its financial and business matters that it was capable of evaluating the merits mad risks of its investment. The recipient had the opportunity to speak with our president and directors on several occasions prior to its investment decision.

The following table sets forth summary financial data derived from our financial statements. The data should be read in conjunction with the financial statements, related notes and other financial information included in this Form 10-K.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

We are an oil and gas exploration, development and production company. Our properties are located in the Cherokee and Forrest Basins along the Kansas and Missouri border. Our corporate strategy is to continue building value in Petrol through the development and acquisition of gas and oil assets that exhibit consistent, predictable, and long-lived production. Our current focus is Coal Bed Methane reservoirs in the central U.S., which produce both Coal Bed Methane (“CBM”) and at times conventional gas.

Results of Operations for the Fiscal Years Ended December 31, 2006 and 2005.

The following table summarizes selected items from the statement of operations at December 31, 2006 compared to December 31, 2005.

Revenues for the fiscal year ended December 31, 2006 were $6,532,798 compared to revenues of $5,244,806 in the fiscal year ended December 31, 2005. This resulted in an increase of $1,287,992 or 25%, from the same period one year ago. The increase in revenues is a result of increases in overall gas production and sales as well as higher hedged prices of our gas and higher daily spot gas prices for the first 8 months of 2006.

	Fiscal Year Ended December 31,
	2006	2005	Increase / (Decrease)
	Amount	Amount	$	%
Expenses:
Direct Costs	2,908,693	3,084,494	$(175,801)	(6%)
Pipeline costs	910,739	230,944	679,795	294%
General and administrative	1,649,028	1,616,334	32,694	(2%)
Professional and consulting Fees	1,957,177	2,577,970	(620,793)	(24%)
Salaries and wages	262,436	264,049	(1,613)	-
Salaries and wages – related party	753,009	234,636	518,373	221%
Depreciation, depletion and amortization	2,811,185	1,392,342	1,418,843	102%
Total expenses	11,252,267	9,400,769	1,851,498	20%

Net operating (loss)	(4,719,469)	(4,155,963)	563,506	14%

Other income (expense):
Interest expense	(3,075,739)	(1,807,833)	1,267,906	70%

Net loss	$(7,795,208)	$(5,963,796)	$1,831,412	31%

Direct costs are the costs associated with operating producing wells, and transporting the oil and natural gas to the market for sale. Direct cost for the fiscal year ended December 31, 2006 was $2,908,693, a decrease of $175,801, or 6%, from $3,084,494 for the fiscal year ended December 31, 2005. The decrease over the prior period is directly attributable to our reduction in costs related to work-overs, repairs and modification to the Neodesha wells and pipeline system that we had previously experienced during the same period in the previous year. We do not anticipate maintenance and work-over costs to that extent in the future and our current direct operating costs are more indicative of our overall production costs.

Pipeline costs for the fiscal year ended December 31, 2006 were $910,739, an increase of $679,795, or 294%, from $230,944 for the fiscal year ended December 31, 2005. The increase in pipeline costs in the current period was partially the result of the addition of our Coal Creek Pipeline as well as additional maintenance costs required in order to maintain in a fully operational status.

General and administrative expenses for the fiscal year ended December 31, 2006 were $1,649,028, an increase of $32,694 or 2%, from $1,616,334 for the fiscal year ended December 31, 2005. The minimal increase in general and administrative expenses is attributable to additional office and administrative costs associated with increased field operations.

Professional and consulting fees for the fiscal year ended December 31, 2006 was $1,957,177, a decrease of $620,793, or 24% from $2,577,970 for the fiscal year ended December 31, 2005. The decrease in professional and consulting fees in the current period was a result of decreased investor relations and accounting fees to our prior CFO.

Salaries and wages for the fiscal year ended December 31, 2006 was $262,436, a decrease of $1,613, or 0.02% from $264,049. As expected, we did not intend to increase staffing levels during our project development stage. Our project managers and support staff for the development of our Coal Creek project were placed during 2005.

Salaries and wages – Officer, for the fiscal year ended December 31, 2006 was $753,009 compared to $234,636 in 2005. The increase in the amount of $518,373 or 221% is primarily due to the amortization of options granted pursuant to his employment agreement of October

2005. In addition, a bonus in the amount of $100,000 was granted by the Board of Directors for the efforts of our CEO in connection with our financing agreements.

Depreciation, depletion, and amortization expense for the fiscal year ended December 31, 2006 was $2,811,185, an increase of $1,418,843, or 102%, from $1,392,342 for the fiscal year ended December 31, 2005. The increase in depreciation, depletion and amortization expense was a result of increased depletion on each unit of production due to our increase in capital expenditures and a decline in reserves.

The net operating loss for the fiscal year ended December 31, 2006 was $4,719,469, versus a net operating loss of $4,155,963 for the fiscal year ended December 31, 2005, a change in net loss of $563,506 or 14%. The increase in net operating loss is attributable to our increase in depletion which was offset slightly by our decrease in professional fees.

Interest expense for the fiscal year ended December 31, 2006 was $3,075,739, an increase of $1,267,906, or 70%, from $1,807,833 for the fiscal year ended December 31, 2005. The increase in interest expense is the result of the increased amount of debt financing received from Laurus Funds, including $1,295,726 attributable to the accretion of warrants issued to Laurus.

Our net loss for the fiscal year ended December 31, 2006 was $7,795,208, an increase of $1,831,412, or 31%, from $5,963,796 for the fiscal year ended December 31, 2005. The increase in net loss is the net result of increased interest expense and operating expense partially offset by increased revenues.

Future payments due on our contractual obligations as of December 31, 2006 are as follows:

In the fiscal year ended December 31, 2006 our cash position decreased by $2,589,024. Our operating activities utilized $2,895,855 of cash mainly from operating expenses we incurred. We also used $12,536,423 of our cash for the capitalized costs of the pipeline, the capitalized cost of drilling more wells and for the acquisition and renewal of oil and gas leases. We repaid $1,833,053 on our notes, borrowed $15,000,000 and paid loan fees of $563,634.

The following overview provides a summary of key information concerning our financial results for the fiscal years ended on December 31, 2005, and 2004.

	Year Ended December 31,
	2005		2004

Revenue
Oil and gas activities	$	6,040,957	$	866,924
Operator fees		796,151		-
Total revenue		5,244,806		866,924

Expenses:
Direct costs		3,084,494		221,339
Pipeline costs		230,944		-
General and administrative		1,616,334		607,617
Professional and consulting fees		2,577,970		1,906,036
Salaries and wages		264,049		225,745
Salaries and wages – related party		234,636		166,667
Depreciation, depletion and amortization		1,392,342		213,475
Acquisition costs		-		654,000
Total expenses		9,400,769		3,994,879

Net operating (loss)		(4,155,963)		(3,127,955)

Other income (expense):
Interest expense, net		(1,807,833)		(1,395,952)
Total other income (expense)		(1,807,833)		(1,395,952)

Net (loss)	$	(5,963,796)	$	(4,523,907)

Fiscal Year Ended on December 31, 2005 Compared to Fiscal Year Ended on December 31, 2004

Revenue: Total revenue was $6,040,957 and $866,924 for the fiscal years ended December 31, 2005 and 2004, respectively, for an increase of $5,174,033 or 597%. The increase in revenues is a result of our acquisition in September of 2004 of 10,000 gross acres of

leaseholds which included 71 producing gas wells in Wilson and Neosho counties in Eastern Kansas. Additionally, we added 14 new wells to our Petrol-Neodesha Project by year end 2005. Revenues from Petrol-Neodesha were our primary source of revenues for year end 2005.

Direct costs are the costs associated with operating producing wells, and transporting the oil and natural gas to the market for sale. Direct costs totaled $3,084,494 and $221,339 for the fiscal year of 2005 and 2004, respectively, for an increase of $2,863,155. The increase in direct costs is primarily the result of increased costs associated with the production of gas in our Petrol-Neodesha project. As a result of our revenue increase related to the Petrol-Neodesha, we had increased costs directly related to the production of gas.

Pipeline costs totaled $230,944 and $0 for the fiscal year of 2005 and 2004, respectively, for an increase of $230,944, relating to our increased production of gas in our Petrol-Neodesha project.

General and administrative expenses for the fiscal year ended December 31, 2005 were $1,616,334 compared to $607,617 in the fiscal year ended December 31, 2004, respectively, for an increase of $1,008,717. The increase is attributable to expenses associated with additional staff and expenses related thereto as the result of increased operations.

Professional and consulting fees were $2,577,970 and $1,906,036 for the fiscal years ended December 31, 2005 and 2004, respectively, an increase of $671,934. The increase is a result of increased oil and gas operations and increased consulting costs associated with the increased operations in addition to increases of legal and accounting related to registrations of our securities primarily related to our additional financing during 2005.

Salaries and wages were $264,049 and $225,745 for the fiscal years ended December 31, 2005 and 2004, respectively, and increase of $38,304. The increase is attributable to increased field operations with the acquisition of our Neodesha field.

Salaries and Wages- Officer’s were $234,636 and $166,667 for the fiscal years ended December 31, 2005 and 2004, respectively, and increase of $67,969 pursuant to Board authorized compensation increase.

Depreciation, depletion, and amortization expense for the fiscal years ended December 31, 2005 and 2004 were $1,392,342 and $213,475 for an increase of $1,178,867. Historically, as a development stage company, we had not placed in service depreciable assets nor had we begun production eliminating the need for a depletion expense. The increase was a result of recently completed acquisition obligations and commencement of production.

Interest Expense for the fiscal years ended December 31, 2005 and 2004 was $(1,807,833) and $(1,395,952), respectively, for an increase of $411,881. The increase in interest expense is the result of increased financing in the sum of $8,000,000, which we borrowed in December of 2004.

Net Loss: Our net loss for fiscal years ended December 31, 2005 and 2004 was $5,963,796 and $4,523,907, respectively, for an increase in net loss in the amount of $1,439,889.

During fiscal year 2005 our cash position increased by approximately $6,642,000. The increase in the cash flow position was from our net financing activities of $9,972,154. This was the result of note proceeds in excess of payments and fee amortization of $9,484,654 and proceeds from the exercise of warrants of $487,500.

We used our cash to acquire and develop oil and gas properties for a net total of $1,694,495. In our operations we used $1,653,341 of cash which is the results of Petrol becoming an operating company for a full year.

In 2007 we plan to continue to focus our efforts on increasing production, improving our asset base, and enhancing our net asset value. We expect to achieve this through the:

Petrol began implementing its development program on the Coal Creek Project in November 2005 with the first $10,000,000 draw down from our $50,000,000 financing arrangement with Laurus Master Funds.

The net proceeds derived from the first Laurus Master Funds Financing transaction were used in the development of two areas within the Coal Creek project, specifically the Burlington area and the Waverly area. This first round of financing allowed Petrol to emplace or complete production wells, salt water disposal wells and install miles of gas gathering pipelines, salt water disposal lines, compressor stations and gas processing systems within those production areas.

Petrol received an additional $15,000,000 from its Laurus Credit facility during the spring of 2006. A portion of these additional funds were used to finalize the completion of some of the original Phase I wells, drilled new CBM wells and add 2 new salt water disposal wells, as well as to continue the integration of the gas gathering and water disposal system and pipelines. In addition to the drilling process Petrol undertook a comprehensive testing program to identify, quantify and rank the most productive water producing intervals.

The Coal Creek Project includes 51 production wells and 5 salt water disposal wells. Initially most of the production wells were connected to the gas gathering systems and water disposal system in order to de-water these CBM wells and promote gas production as quickly and efficiently as possible. During the second half of 2006 it began evident that water production rates from the producing coal seams in both Burlington and Waverly were higher than anticipated and thus two additional salt water disposal were drilled, one in Burlington and one in Waverly. The inclusion of these new SWD’s has almost doubled the available salt water disposal capacity in Burlington and Waverly.

To further our understanding of the water and gas production mechanisms from these multiple coal seams Petrol has concentrated its technical efforts on a cluster of 5-6 closely spaced wells in Burlington and Waverly. Our objective is to de-water these wells and the area around these wells as quickly and effectively as possible thus exposing the gas bearing coal seams directly to the wellbore. The methodology being employed to attain that objective includes:

Although the data from these cluster wells is ongoing and being analyzed it is clear that the permeability of the coal beds manifested by early water production is high and gas rates although still modest appears to improve as the coal beds and the fracture system de-waters.

Since the Burlington area was developed first those wells in addition to having longer and sustained de-watering times also have some conventional sandstone reservoirs and therefore have been selling gas into the Enbridge Interstate pipeline since late April 2006. However the implementation of our testing and analysis efforts involving our cluster wells described above has at times interrupted or curtailed gas production and thus sales.

The Waverly wells have been in various stages of de-watering and the sustained disposal rates improved substantially following the inclusion and operation of a new SWD well in early October 2006. Gas production from the wells is modest and has not as yet reached the level or sustainability to meet Enbridge pipeline requirements.

The entire Coal Creek development plan includes drilling and completing about 540 production wells along with three gas gathering pipeline and gas processing systems. The pace of the development will obviously depend on the availability of the financing program, the economic and technical conclusions based on the analysis of our cluster well program and favorable market conditions.

Our future financial results will depend primarily on: (i) the ability to continue to produce gas and oil from existing wells; (ii) the ability to discover commercial quantities of natural gas

and oil; (iii) the market price for oil and gas; and (iv) the ability to fully implement our exploration and development program, which is dependent on the availability of capital resources. In order to be successful in all or any of these respects, the prices of oil and gas prevailing at the time of production must be at a level allowing for profitable production, and we must be able to obtain additional funding to increase our capital resources.

Petrol-Neodesha and our oil properties currently provide ongoing revenue and cash from sales of oil and gas. As we expand development and operational activities, we will weigh the pace of further drilling and development against the availability of internal and external funding. The technical and base economics issues in Petrol-Neodesha are clear and thus continued development involves far less risk than might be expected in new un-development areas. Given appropriate economics we plan to continue with that development rate.

With the enhancements to gas gathering pipeline systems that Petrol finalized late spring and early summer of 2005 we now have additional pipeline capacity to fully develop this 10,000 gross acre property. During 2006 we have added a total of 17 new or re-completed production wells to the 14 new production wells we drilled and completed in 2005. All 31 new production wells were 100% successes.

During the second and third quarters of 2006 we initiated a technical program designed to improve our overall understanding of the effectiveness of multi-zone stimulations and their ability to enhance production and reduce stimulation costs. Our expectations are to implement this program throughout the year employing advanced stimulation methodologies and re-completion techniques. Real time data acquisition and state-of-the-art fracture modeling were employed on several of our multi-stage fracture stimulations. The information derived during these tests provided both our field project personnel and the fracture service company with a much improved understanding of the physical processes that may be occurring about 1,500 ft below the surface. Further with real time data and modeling it allows the fracture stimulation process to be altered and improved instantly. Petrol retained Pinnacle Technologies of Houston and Pentagon Technical Services of Denver to provide technical consulting and field support on specific fracturing/chemical strategies to optimize our completion techniques, reduce operational costs and improve production at our Neodesha and Coal Creek project areas.

The following table summarizes total assets, accumulated deficit, stockholders’ equity and working capital at December 31, 2006 compared to December 31, 2005.

Financing. On October 28, 2004, we entered into agreements with Laurus Master Fund, Ltd., a Cayman Islands corporation. Under the terms of the Laurus Funds agreements we issued a Secured Convertible Term Note (the “Note”) in the aggregate principal amount of $8,000,000 and a five-year warrant (the “Warrant”) to purchase 3,520,000 shares of our common stock at $2.00 per share and 1,813,333 shares of our common stock at $3.00 per share. On June 2, 2006, Laurus transferred the 5,333,333 warrants to Pallas Production Corp. (“Pallas”). The Note is convertible into shares of our common stock at a fixed conversion price of $1.50 per share. The Note has a three-year term and bears an interest rate equivalent to the “prime rate” published by the Wall Street Journal from time to time plus 3%, subject to a floor of 7.5% per annum.

On January 28, 2005, we amended the Laurus Note and the Registration Rights Agreement. Laurus agreed to move five months of principal payments (January through May of 2005) to be paid on the Maturity Date (October 28, 2007). Additionally, Laurus agreed to extend certain filing and effectiveness dates under the registration rights agreement. In consideration for the amendment, we issued an additional common stock purchase warrant to Laurus to purchase up to 1,000,000 shares of our common stock at $2.50 per share for the first 666,667 shares and $3.00 per share for the remaining 333,333 shares. On June 20, 2006, Laurus transferred the 1,000,000 warrants to Pallas. Further, pursuant to the amendment agreement executed on April 28, 2004, we have agreed to file semi-annual registration statements to register shares of our common stock issued to Laurus for the conversion of interest under the Note.

As of December 31, 2006, Laurus has converted $2,283,823 of principal payments into 1,522,550 shares of our common stock and $779,352 of accrued interest into 519,568 shares of our common stock (2,042,118 shares in total). The conversion of principal and accrued interest allowed us additional cash to use in our operations.

On October 31, 2005, we entered into another financing agreement with Laurus, under which $10,000,000 was funded into an escrow account and was disbursed to us in November 2005 after finalization of certain closing requirements. We issued a three-year Secured Term Note in the aggregate principal amount of $10,000,000 and a five-year warrant to purchase 1,000,000 shares of our common stock at $2.00 per share. The note bears an interest rate equivalent to the “prime rate” published by the Wall Street Journal from time to time plus 3.25%, subject to a floor of 10% and a ceiling of 14% per annum. In addition, Laurus, in their sole discretion, may purchase additional notes from us in an aggregate principal amount of up to $40,000,000 pursuant to substantially similar terms of the initial note dated October 31, 2005.

On March 31, 2006, we entered into agreements with Laurus to draw down an additional $5,000,000 under the credit facility provided by Laurus in October 2005. Under the terms of the Laurus agreements we issued a Secured Term Note in the aggregate principal amount of $5,000,000 and a five-year warrant to purchase 200,000 shares of our common stock at $1.80 per share. On June 20, 2006, Laurus transferred the 200,000 warrants to Pallas. The Note has a three-year term and bears an interest rate equivalent to the “prime rate” published by the Wall Street Journal from time to time plus 3.25%, subject to a floor of 10% and a ceiling of 14% per annum. Concurrently with the agreements listed above, we amended and restated our previous $10,000,000 Secured Term Note dated October 31, 2005 with Laurus.

On April 7, 2006, the funds were released from Escrow. Net proceeds to Petrol from the financing, after payment of fees and expenses to Laurus and its affiliates, were $4,806,688. The proceeds are being utilized by Petrol for drilling activities on our Coal Creek Project.

On May 31, 2006, we entered into agreements with Laurus to draw down an additional $10,000,000 under the credit facility provided by Laurus in October 2005. Under the terms of the Laurus agreements we issued a Secured Term Note in the aggregate principal amount of $10,000,000 and a five-year warrant to purchase 400,000 shares of our common stock at $1.65 per share. The Note has a three-year term and bears an interest rate equivalent to the “prime rate” published by the Wall Street Journal from time to time plus 3.25%, subject to a floor of 10% and a ceiling of 14% per annum. Concurrently with the execution of the new Laurus Funds agreements, Petrol amended and restated its previous $10,000,000 Secured Term Note dated October 31, 2005 and the $5,000,000 Secured Term Note dated March 31, 2006 with Laurus Funds.

On June 2, 2006, the funds were released from Escrow. Net proceeds to Petrol from the financing, after payment of fees and expenses to Laurus Funds and its affiliates, were $9,629,679. The proceeds will be utilized by Petrol for drilling activities on Petrol’s Coal Creek Project.

Cash Flows. Since inception, we have financed cash flow requirements through debt financing, the issuance of common stock and revenues generated from the sale of oil and gas. As we expand operational activities, we may experience net negative cash flows from operations, pending receipt of sales or development fees, and may be required to obtain additional financing to fund operations through common stock offerings and debt borrowings to the extent necessary to provide working capital.

A critical component of our operating plan impacting our continued existence is to efficiently manage the production from our Petrol-Neodesha Development and successfully develop our Coal Creek Project. Our ability to obtain additional capital through additional equity and/or debt financing, and Joint Venture or Working Interest partnerships will also be important to our expansion plans. In the event we experience any significant problems assimilating acquired assets into our operations or cannot obtain the necessary capital to pursue our strategic

plan, we may have to reduce the growth of our operations. This may materially impact our ability to increase revenue and continue our growth.

We believe that our existing capital combined with cash flow from operations will only be sufficient to sustain our operations, without additional financing, through fiscal 2007.

We may incur operating losses over the next twelve months. Our lack of operating history particularly at Coal Creek makes predictions of future operating results difficult to ascertain. Our prospects must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of development and production, particularly companies in the oil and gas industry. Such risks include, but are not limited to, an evolving and unpredictable business model and the management of growth. To address these risks we must, among other things, implement and successfully execute our business and marketing strategy, continue to develop and upgrade technology and products, respond to competitive developments, and attract, retain and motivate qualified personnel. There can be no assurance that we will be successful in addressing such risks, and the failure to do so can have a material adverse effect on our business prospects, financial condition and results of operations.

Under our current operating plan, we are required to make certain lease payments to maintain our rights to develop and drill for oil and gas. These lease payments are material obligations to us.

Summary of product and research and development that we will perform for the term of our plan.

Our original Operation Plan for field development included a mix of lease acquisition and the purchase of existing producing properties. It started with identifying the most promising and cost-effective drill sites on our current leased acres, drilling and testing wells to prove reserves, completing the more promising test wells, extracting the gas, oil and other hydrocarbons that we find, and delivering them to market.

In October 2004 we purchased an existing 10,000 gross area gas producing property we called Petrol-Neodesha. Petrol-Neodesha provided us with revenue and an opportunity to enhance production in a producing area as well as gain important hands on experience and insight into the field wide development slated for Coal Creek.

In 2005 we believed that we had leased sufficient mineral acreage in and around Coffey County, KS to move forward with field development of the area and with the proceeds of financing with Laurus Master Funds we proceeded with the development of our Coal Creek Project. That development accelerated in early 2006 and continues throughout the year.

Our plan called for an exploration and development phase involving the drilling and testing of 18 exploratory wells in the Coal Creek project. Data and analysis acquired from these initial test wells provided our geologists and engineers with information that supported the quantitative determination concerning the gas content, reserve estimates and potential to produce commercial rates of CBM and other types of more conventional natural gas. By design most of these wells were located in proximity to an existing interstate gas pipeline. The total drilling depth of exploratory wells in Coal Creek was approximately 1,700 ft.

Kansas Geologic Society (KGS) joined us in our field operations to help in assessing the gas reserves from our CBM exploratory/test wells in the Coal Creek Project. KGS took samples from multiple coal beds found at various depths in these test wells. They performed laboratory type analysis to acquire gas content in the coals. Their laboratory results yielded values similar to those obtained by our geologist, Mr. William Stoeckinger, from sampling of some of our other exploratory/test wells. We view these independent gas content values quite favorably since they indicate quantitative similarities to the CBM producing coal beds found in our Petrol-Neodesha Project just south of the Coal Creek Project.

Based on our first series of exploratory/test wells and current bid pricing we anticipate that each well in our Coal Creek Project will cost approximately $180,000, which includes locating, drilling, testing, hydraulically fracturing and connecting to the gas gathering pipeline. Operational costs are expected to be about $1,150 per month per well to pay for electricity, pulling and repairs, pumping, general maintenance and other miscellaneous charges. In support of these operations we have working agreements with local third parties to monitor and maintain our wells and perform drilling and work-over activities

Our Independent Reserve Report dated December 31, 2005 indicated we had significant proven undeveloped gas reserves on our leases in the Coal Creek Project to warrant development and thus in November 2005 with these and the other technical data described above we began the development of the Coal Creek Project with the intent of producing those reserves, increasing revenues and enhancing the Net Asset Value of that Project area.

Coal Creek has 51 production wells and 5 SWD wells with 32 of those production wells and 3 SWD wells located in the Burlington area and 19 of those production wells and 2 SWD well located in the Waverly area. Each area has its own gas gathering pipelines, water disposal lines, compressors and gas processing equipment to make connections with the Enbridge interstate pipeline.

Early water production from these Coal Creek producing intervals was found to be considerably higher than those found in the more mature production intervals of our Neodesha wells. Further, as many as 10-12 coal beds and shales were completed in the Coal Creek project wells compared to 2-3 coal beds normally completed in the Neodesha wells thus compounding the comparison between the two areas. To further our understanding of the water and gas production mechanisms from these multiple coal seams in Coal Creek Petrol has concentrated its technical efforts on some closely spaced cluster wells. Our objective is to de-water these wells

and the area around these wells as quickly and efficiently as possible thus exposing the gas bearing coal seams directly to the wellbore and acquire as much technical data as possible.

Some of the Coal Creek wells that were developed first in addition to having longer and sustained de-watering times also have some conventional sandstone reservoirs and therefore have been selling gas into the Enbridge Interstate pipeline. However the implementation of our testing and analysis efforts involving our cluster wells described above has at times interrupted or curtailed gas production and thus sales.

Petrol plans to continue the development of its Coal Creek Project with the pace and timing of the development depending on the availability of financing, the economic and technical conclusions based on the analysis of our cluster well program and favorable market conditions.

Our Petrol-Neodesha project has room for another 50 to 100 wells to be drilled or re-completed in new reservoirs in order to fully develop this existing 10,000 gross leased mineral acreage. In 2005, we finalized enhancing the production capacity of our gas gathering system which included the addition of several new booster pumps and miles of larger diameter trunk lines that will accommodate production for all our new or re-completed wells. During 2006, Petrol drilled or re-completed 17 production wells on the Petrol-Neodesha properties, with a 100% success rate. All these new wells have been connected to our gas gathering pipeline system.

We plan to continue implementing our Neodesha development that includes implementing technical programs employing advanced stimulation methodologies and re-completion techniques. These technical programs are designed to improve our overall understanding of the effectiveness of multi-zone stimulations and their ability to enhance production and reduce stimulation costs.

With cumulative gas production for 2006 from Petrol-Neodesha reaching a new high of about 0.998 Bcf we expect to continue seeking acquisition opportunities which compliment this current production area and expand the field wide development of Petrol-Neodesha.

Petrol’s field development plans and strategies are employed throughout its multiple project areas and incorporates several assessment stages. Each new well is drilled through all possible CBM reservoirs and individually evaluated. Upon a favorable evaluation of its overall production capacity the well will be fully completed in as many gas producing intervals as possible and then connected to our local gas gathering and water disposal pipelines.

When a proposed drilling site is identified, as a licensed operator in the State of Kansas and Missouri, Petrol is engaged in all aspects of well site operations. As a state licensed operator we are responsible for permitting the well, which includes obtaining permission from the Kansas Oil and Gas Commission or Missouri relative to spacing requirements and any other county, state and federal environmental regulatory issues required at the time that the permitting process commences. Additionally, Petrol formulates and delivers to all interest owners an operating agreement establishing each participant’s rights and obligations in that particular well based on the location of the well and the ownership. In addition to the permitting process, we as the operator are responsible for hiring the driller, geologist and land men to make final decisions relative to the zones to be targeted, confirming that we have good title to each leased parcel covered by the spacing permit and to actually drill the well to the target zones. Petrol is responsible for completing each successful well and connecting it to the most appropriate section of the gas gathering system.

As the operator we are also the caretaker of the well once production has commenced. We are responsible for paying bills related to the drilling and development of the well, billing working interest owners for their proportionate expenses in drilling and completing the well, and selling the production from the well. Once the production is sold, we anticipate that the purchaser thereof carries out its own research with respect to ownership of that production and sends out a division order to confirm the nature and amount of each interest owned by each interest owner. Once a division order has been established and confirmed by the interest owners, the production purchaser issues the checks to each interest owner in accordance with its appropriate interest. From that point forward, we as operator are responsible for maintaining the well and the well site during the entire term of the production or until such time as we have been replaced or the site appropriately abandoned.

Along with the drilling and completion of our production wells our subsidiary pipeline companies formulate, design and install a gas gathering and compression system to transport the gas from wellhead to the high pressure interstate pipeline tap and sales market. Our experience in Petrol-Neodesha is being brought to bear on our new development area in Coal Creek and eventually to Missouri. We have identified several major interstate distribution pipelines that operate within and pass through the counties in which we have lease holdings. These include pipelines owned and operated by Southern Star, CMS Energy, Enbridge and Kinder Morgan. We have initiated contact with these companies to ascertain the specific locations of their pipelines, their requirements to transport gas from us (including volume of gas and quality of gas), and the costs to connect to their pipelines. We currently have agreements with Southern Star in our Petrol-Neodesha Project and Enbridge in our Coal Creek Project

Petrol continues to update the costs of transporting our gas products from the producing wells to the nearest appropriate interstate pipeline. The cost of installing a distribution infrastructure or local gathering system varies depending upon the distance the gas must travel from wellhead to the compressor station and high pressure pipeline tap, and whether the gas must be treated to meet the purchasing company’s quality standards. However, based on the close proximity of several major distribution pipelines to our leased properties, plus our intent to drill as close to these pipelines as practicable, at present we estimate the total cost of installing a distribution infrastructure for a group of about 50-75 producing wells to be approximately

$6,500-7,500 each plus a one-time expense of $5,000 per well to tap into the high pressure interstate pipeline and support a compressor and monitoring system.

The price obtained for produced oil and gas is dependent on numerous factors beyond our control, including domestic and foreign production rates of oil and gas, market demand and the effect of governmental regulations and incentives. To reduce the impact of these extraneous factors we often enter into forward sales contracts for a portion of the gas and oil we produce. However, we do not have any delivery commitments for gas or oil from wells not currently drilled or producing. Because the U.S. government’s has been encouraging increases in domestic production of energy, coupled with the high demand for natural gas, we do not anticipate any difficulties in selling any oil and gas we produce, once it has been delivered to a distribution facility.

The timing of most of our capital expenditures is discretionary. Currently there are no material long-term commitments associated with any capital expenditure plans or that are currently in the investigative planning stage. Consequently, we have a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant. The level of our capital expenditures will vary in future periods depending on energy market conditions and other related economic factors.

We currently have eight full time employees and two part time employees as well as twelve contract personnel that support and operate our field operations. We do not anticipate a significant change in the number of full time employees over the next twelve months. We intend to use the services of independent consultants and contractors to perform various professional services, particularly in the area of land services, drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain general and administrative expenses.

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results or operations, liquidity, capital expenditures or capital resources that is material to investors.

To reduce our exposure to unfavorable changes in natural gas prices we have entered into an agreement to utilize energy swaps in order to have a fixed-price contract. This contract allows us to be able to predict with greater certainty the effective natural gas prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided under the contracts. However, we will not benefit from market prices that are higher than the fixed prices in our contracts for hedged production. If we are

unable to provide the quantity that we have contracted for we will have to go to the open market to purchase the required amounts that we have contracted to provide.

The following table summarizes our fixed price contracts as of December 31, 2006:

On October 9, 2006, we entered into a “Fixed Price Contract” to sell 1,000.0 DTH per day of our natural gas productions at a fixed price of $7.32 per DTH. The contract period begins April 1, 2007 and expires on March 31, 2008.

Our accounting estimates include bad debts on our receivables, amount of depletion of our oil and gas properties subject to amortization, the asset retirement obligation and the value of the options and warrants that we issue. Our trade receivables have been fully collectible since inception and we only have sales to a small base of customers. We believe that all of our receivables are collectible. The depletion of our oil and gas properties is based in part on the evaluation of our reserves and an estimate of our reserves. We obtain an evaluation of the proved reserves from a professional engineering company and on a quarterly basis we review the estimates and determine if any adjustments are needed. If the actual reserves are less than the estimated reserves we would not fully deplete our costs. The asset retirement obligation relates to the plug and abandonment costs when our wells are no longer useful. We determine the value of the liability by obtaining quotes for this service and estimate the increase we will face in the future. We then discount the future value based on an intrinsic interest rate that is appropriate for Petrol. If costs rise more than what we have expected there could be additional charges in the future however we monitor the costs of the abandoned wells and we will adjust this liability if necessary. The value we assign to the options and warrants that we issue is based on the fair market value as calculated by the Black-Scholes pricing model. To perform a calculation of the value of our options and warrants we determine the volatility of our stock. We believe our estimate of volatility is reasonable and we review the assumptions used to determine this whenever we have an equity instrument that needs a fair market value. Although the offset to the valuation is in paid in capital were we to have an incorrect material volatility assumption our expenses could be understated or overstated. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. We base our

assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, mechanical problems, general business conditions and other factors.

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Material changes in prices impact revenue stream, estimates of future reserves, borrowing base calculations of bank loans and value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate the increased business costs will continue while the commodity prices for oil and natural gas, and the demand for services related to production and exploration, both remain high (from a historical context) in the near term.

Our major market risk exposure is in the pricing applicable to our oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas production. Historically, prices received for oil and gas production have been volatile and unpredictable and price volatility is expected to continue.

Monthly oil price realizations ranged from a low of approximately $40.73 per barrel to a high of approximately $64.00 per barrel during 2005 and as high as $56.00 per barrel during the year ended December 31, 2006. Gas price realizations ranged from a monthly low of approximately $4.24 per Mcf to a monthly high of approximately $9.37 per Mcf during the same period.

Since new well development is an ongoing program, management expects revenue to grow in the foreseeable future. In order to reduce natural gas price volatility, we have entered into hedging transactions.

Normal hedging arrangements have the effect of locking in for specified periods the prices we would receive for the volumes and commodity to which the hedge relates. Consequently, while hedges are designed to decrease exposure to price decreases, they also have the effect of limiting the benefit of price increases.

Our long term debt with Laurus Funds has a floating interest rate of prime plus 3% to 3.25%, with a floor of 7.5% to 14%. Therefore, interest rate changes will impact future results of operations and cash flows.

See Index to Financial Statements and Financial Statement Schedules appearing on page F-1 through F-31 of this Form 10-K.

Petrol has had no disagreements with its independent auditors on accounting or financial disclosures.

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports filed under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the specified time periods. As of the end of the period covered by this report, Paul Branagan, our Chief Executive Officer and Principal Financial Officer evaluated the effectiveness of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based on the evaluation, which disclosed no significant deficiencies or material weaknesses, Mr. Branagan, our Chief Executive Officer and Principal Financial Officer concluded that our disclosure controls and procedures are effective in timely alerting him to material information required to be included in our periodic SEC filings.

It should be noted, however, that no matter how well designed and operated, a control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events. Because of these and other inherent limitations of control systems (including faulty judgments in decision making or breakdowns resulting from simple errors or mistakes), there can be no assurance that any design will succeed in achieving its stated goals under all potential conditions. Additionally, controls can be circumvented by individual acts, collusion or by management override of the controls in place.

There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The members of our board of directors serve for one year terms and are elected at the next annual meeting of stockholders, or until their successors have been elected. The officers serve at the pleasure of the board of directors.

On December 8, 2006, the Registrant’s Board of Directors nominated and elected Robert H. Kite and Duane D. Fadness to serve on the Board of Directors for the Registrant. Mr. Kite’s and Mr. Fadness’ term will continue until the next annual stockholder’s meeting or until their successors are duly appointed.

Paul Branagan, age 63, is the President, CEO and a Director of Petrol and has been a director since 2002. Mr. Branagan graduated from the University of Las Vegas Nevada with a B.S. in physics. From 1993 to the present Mr. Branagan has been the President and Senior Scientist of Branagan & Associates, Inc. From 1975 to 1993 he was the Project Manager, Assistant Oil and Gas Division Manager and Senior Scientist of CER Corporation of Las Vegas, Nevada.

Loren W. Moll, age 50, is Chairman of Petrol, has been a member of the law firm of Caldwell & Moll, L.C. in Overland Park, Kansas since its establishment in November 1996. Mr. Moll concentrates his practice in all areas of real estate law, including commercial real estate transactions, breach of contract, escrow and title disputes, commercial leasehold disputes, real estate broker liability, and oil and gas. Mr. Moll holds a B.A. degree from the University of Kansas (1983) and his Juris Doctor degree, Order of the Coif, from the University of Kansas School of Law (1986) where he was Research Editor for the University of Kansas Law Review. Mr. Moll was formerly a partner of the real estate law firm Lewis, Rice & Fingersh from 1986 to 1994 and was associated with the international law firm Bryan Cave LLP from 1994 to 1996.

Suzanne Herring, age 42, has been a director of Petrol since 2005. Ms. Herring has over 19 years of experience in the public and private accounting arenas. She has worked as an auditor of public and non-public companies and has served as a chief financial officer for multiple businesses. Further, Ms. Herring has a broad individual and corporate taxation background. Since February 2005, Ms. Herring has been president of Accuity Financial Services, Inc. (formerly Opus Pointe), a Las Vegas, Nevada based consulting firm specializing in providing contract CFO services and internal control compliance and implementation to publicly traded small business issuers. From 1995 to present, Ms. Herring has owned and operated American West Financial Services, a Las Vegas, Nevada based financial and taxation consulting firm. From 2003 through 2005, Ms. Herring was an auditor for a Las Vegas, Nevada based CPA firm, Beckstead and Watts, LLP. Ms. Herring is also a former director of New Vista Ranch Charitable Organization. In addition, Ms. Herring also serves as the Chief Financial Officer of AFV Solutions, Inc., a 34 Act reporting company in the alternative fuel industry (OTC:BB-“AFVS”), and as a director of Rubicon Financial Incorporated, a 34 Act reporting company in the financial services industry (OTC:BB-“RBCF”).

Robert H. Kite, age 52, has been director of Petrol since December 8, 2006. Since 1991, Mr. Kite has served on the Board of Directors, and Audit Committee Member, of National Energy Group, Inc., a management company engaged in the business of management, development, production and operations of oil and natural gas properties, primarily located in Texas, Oklahoma, Arkansas, and Louisiana (both onshore and in the Gulf of Mexico). Since 1981, Mr. Kite has served as the President and Chief Operating Officer of KFC Inc., the managing general partner of KFT LLP, a family-owned company with operations that include real estate development, investments and medical MRI clinics. Since 1982, Mr. Kite has also served as President and CEO of Roamin’ Korp. Inc., a private holding company involved in real estate, equities, and other investments. Since 2002, Mr. Kite has served on the Board of Directors of E-2020, a private educational resource company, and has also served on the Board of Directors, Governance Committee and is a Member of the Audit Committee of ANTs software, inc. In addition, since 2005, Mr. Kite has served on the Board of Directors of Jardinier Corporation. Between 1995 and 2005, Mr. Kite served on the Board of the FBI Citizens Academy Charter Board of Phoenix, Arizona and served as the Board’s President in 1998. From 1998 to present, Mr. Kite has served on the Board of Directors of Child Help USA, a non-profit organization. Mr. Kite earned a B.S. Degree in Psychology and Political Science with a minor in Business from Southern Methodist University.

Duane D. Fadness, age 58, has been director of Petrol since December 8, 2006. Mr. Fadness has more than 25 years of experience in the oil and gas industry in the United States, Canada and Europe. His board-level experience includes virtually all aspects of the financing and management of oil and gas properties. He has successfully managed the coordination of oil and gas exploration and development projects and has structured lease/property acquisitions and drilling ventures. In the early 1980s, Mr. Fadness served as a Special Projects Landman for the Hunt family of Dallas, Texas. From 1998 to present, Mr. Fadness has been employed by Western Gas Resources, Inc./Lance Oil & Gas Co., Inc. in Denver, Colorado. Mr. Fadness has served as their Consulting Petroleum Landman (1998-2001), as their Senior Business Development Representative (2001-2002) and as their Land Manager (2002 to present). Mr. Fadness, a Certified Professional Landman, earned his Master of Business Administration Degree from the University of Denver.

Subsequent to year-end, Messrs. Branagan and Moll have each provided us with information indicating their intentions not to stand for re-election to the board of directors at the next annual stockholders’ meeting.

Pursuant to the Nevada General Corporation Law, our Articles of Incorporation exclude personal liability for our Directors for monetary damages based upon any violation of their fiduciary duties as Directors, except as to liability for any breach of the duty of loyalty, acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, or any transaction from which a Director receives an improper personal benefit. This exclusion of liability does not limit any right which a Director may have to be indemnified and does not affect any Director’s liability under federal or applicable state securities laws. We have agreed to indemnify our directors against expenses, judgments, and amounts paid in settlement in connection with any claim against a Director if he acted in good faith and in a manner he believed to be in our best interests.

Directors are elected to serve until the next annual meeting of stockholders and until their successors have been elected and qualified. Officers are appointed to serve until the meeting of the Board of Directors following the next annual meeting of stockholders and until their successors have been elected and qualified.

Julie Heimerman, step-daughter of Paul Branagan, Petrol’s chief executive officer, is an administrative employee at Petrol’s executive office.

No Executive Officer or Director of the Corporation has been the subject of any Order, Judgment, or Decree of any Court of competent jurisdiction, or any regulatory agency permanently or temporarily enjoining, barring suspending or otherwise limiting him/her from acting as an investment advisor, underwriter, broker or dealer in the securities industry, or as an affiliated person, director or employee of an investment company, bank, savings and loan association, or insurance company or from engaging in or continuing any conduct or practice in connection with any such activity or in connection with the purchase or sale of any securities.

No Executive Officer or Director of the Corporation has been convicted in any criminal proceeding (excluding traffic violations) or is the subject of a criminal proceeding which is currently pending.

Pursuant to our financing agreements with Laurus Master Fund, Ltd., the occurrence of a change of control in the controlling ownership of Petrol would be a default under the agreements. A change in control (as defined below) shall occur with respect to Petrol, unless Laurus shall have expressly consented to such change of control in writing. A “Change of Control” shall mean any event or circumstance as a result of which (i) any “Person” or “Group” (as such terms are defined in Sections 13(d) and 14(d) of the Exchange Act), other than Laurus, is or becomes the “beneficial owner” (as defined in Rules 13(d)-3 and 13(d)-5 under the Exchange Act), directly or indirectly, of 35% or more on a fully diluted basis of the outstanding voting equity interest of Petrol, (ii) the Board of Directors of Petrol shall cease to consist of a majority of Petrol’s board of directors at the time of the execution of the Laurus Agreements (Paul Branagan, Loren Moll and Suzanne Herring were the only board members at the time of the execution of the Laurus Agreements subject to this provision), as amended or ratified, or (iii) Petrol or any of its Subsidiaries merges or consolidates with, or sells all or substantially all of its assets to, any other person or entity.

Section 16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), requires our executive officers and directors, and persons who beneficially own more than ten percent of our common stock, to file initial reports of ownership and reports of changes in ownership with the SEC. Executive officers, directors and greater than ten percent beneficial owners are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file. Based upon a review of the copies of such forms furnished to us and written representations from our executive officers and directors, we believe that as of the date of this filing they were all current in there filings.

On November 18, 2005, we adopted a Code of Business Conduct and Ethics that applies to our Directors, officers and employees. A copy of the Code of Business Conduct and Ethics is attached as Appendix A to the proxy filed with the SEC on November 22, 2005 and is also available on our website at www.petroloilandgas.com.

At present, the Nominating Committee determines nominees for Directors. Our Directors approved the selection of the nominees for Directors named in this proxy statement.

Generally, nominees for Directors are identified and suggested by the members of the Board or management using their business networks. The Board has not retained any executive search firms or other third parties to identify or evaluate director candidates in the past and does not intend to in the near future. In selecting a nominee for director, the Nominating Committee considers the following criteria:

The Nominating Committee has not established any specific minimum qualifications that a candidate for director must meet in order to be recommended for Board membership. Rather the Nominating Committee will evaluate the mix of skills and experience that the candidate offers, consider how a given candidate meets the Board’s current expectations with respect to each such criterion and make a determination regarding whether a candidate should be recommended to the stockholders for election as a director. During 2006, Petrol received no recommendation for Directors from its stockholders.

Petrol will consider for inclusion in its nominations of new Board of Director nominees proposed by stockholders who have held at least 1% of the outstanding voting securities of Petrol for at least one year. Board candidates referred by such stockholders will be considered on the same basis as Board candidates referred from other sources. Any stockholder who wishes to

recommend for Petrol’s consideration a prospective nominee to serve on the Board of Directors may do so by giving the candidate’s name and qualifications in writing to Petrol’s Secretary at the following address: Corporate Woods, Building 51, 9393 West 110^th Street, Suite 500, Overland Park, Kansas 66210.

A copy of the Governance and Nominating Committee Charter is available on our website at www.petroloilandgas.com.

Prior to December 20, 2005, we did not have an Audit Committee and our Board of Directors performed the necessary functions of an Audit Committee, such as: recommending a firm of independent certified public accountants to audit the annual financial statements; reviewing the independent auditors independence, the financial statements, and their audit report; and reviewing management’s administration of the system of internal accounting controls.

On December 20, 2005, we established and appointed members of the Board to the Audit Committee in accordance with section 3(a)(58)(A) of the Securities Exchange Act of 1934 in anticipation of making an application to list our common stock on the American Stock Exchange. The Audit Committee was comprised of two directors; Ms. Herring (Chairman) and Mr. Moll.

On October 5, 2006, we disbanded the Audit Committee because of our inability to meet the initial listing standards for the American Stock Exchange. We currently have an audit committee charter in place but as a result of the disbandment of the Audit Committee we no longer operate under the charter and our Board of Directors will now perform certain functions as the Audit Committee.

The Board of Director’s (the “Board”) has responsibility for establishing, implementing and continually monitoring adherence with Petrol’s compensation philosophy. The Board ensures that the total compensation paid to the Executives is fair, reasonable and competitive. We do not currently have a Compensation Committee.

The Board believes that the most effective executive compensation program is one that is designed to reward the achievement of specific annual, long-term and strategic goals by Petrol, and which aligns executives’ interests with those of the stockholders by rewarding performance above established goals, with the ultimate objective of improving stockholder value. As a result of the size of Petrol and only having one executive officer, the Board evaluates both performance and compensation on an informal basis. Upon hiring additional executives, the Board intends on establishing a Compensation Committee to evaluate both performance and compensation to ensure that Petrol maintains its ability to attract and retain superior employees in key positions

and that compensation provided to key employees remains competitive relative to the compensation paid to similarly situated executives of our peer companies. To that end, the Board believes executive compensation packages provided by Petrol to its executives, including the named executive officers, should include both cash and stock-based compensation that reward performance as measured against established goals.

The Board makes all compensation decisions for the Executives and approves recommendation regarding equity awards to all elected officers of Petrol. Decisions regarding the non-equity compensation of other executive officers are made by the Board.

Based on the foregoing objectives, the Board has structured Petrol’s annual and long-term incentive-based cash and non-cash executive compensation to motivate executives to achieve the business goals set by Petrol and reward the executives for achieving such goals.

For the fiscal year ended December 31, 2006, Petrol continued to have only one executive officer, whose contract was executed on November 2, 2005. Therefore, Petrol took no actions during 2006 relative to Executive Compensation.

The table below summarizes the total compensation paid or earned by our executive officer Paul Branagan and our former non-executive employee Gary Bridwell for the fiscal year ended December 31, 2006.

SUMMARY COMPENSATION TABLE
Name and Principal Position (a)	Year (b)	Salary ($) (c)	Bonus ($) (d)	Stock Awards ($) (e)	Option Awards ($) (f)	Non-Equity Incentive Plan Compen-sation ($) (g)	Nonqualified Deferred Compensation Earnings ($) (h)	All Other Compen-sation ($) (i)	Total ($) (j)
Paul Branagan,
CEO/President	2006	$230,625	$105,000	-0-	-0-	-0-	-0-	$76,511(1)	$412,136

Gary Bridwell,
Field Operations Manager (2)	2006	$120,000	$5,000	-0-	-0-	-0-	-0-	-0-	$125,000

Employment and Other Contracts; Potential Payments Upon Termination or Change-in-Control

On November 2, 2005, we entered into an employment agreement with Paul Branagan, wherein Mr. Branagan agreed to serve as Petrol’s Chief Executive Officer and President. The term of employment is for five (5) years, ending on September 30, 2010. We agreed to pay Mr. Branagan annual compensation of $225,000, and effective the 30^th of September for each successive year that his Agreement is in effect, his compensation is adjusted by a ten percent (10%) increase. In addition to the cash compensation, we granted Mr. Branagan an extension of previously granted stock options to purchase 1,250,000 shares of our common stock at prices ranging from $0.05 per share to $2.50 per share, exercisable at any time and expiring on September 30, 2010. We also granted Mr. Branagan additional options to purchase 500,000 shares of our common stock at $1.75 per share, exercisable at any time and expiring on September 30, 2010. Mr. Branagan will also receive a 1/100 Over Riding Royalty on production from any wells completed on our current and future leased acreage. The Over Riding Royalty shall be paid as determined by our Board of Directors and the term of the payment of the Over Riding Royalty shall be in perpetuity.

Additional Benefits. During his employment term, Mr. Branagan is entitled to receive all other benefits of employment generally available to Petrol’s other executive and managerial employees, in addition to the following:

We have entered into an employment agreement with Paul Branagan, our chief executive officer. Mr. Branagan’s employment agreement allows for him to resign for good reason upon a change in control of Petrol. Upon his resignation for good reason, Mr. Branagan would continue to receive, through the end of the Term of this Agreement, his salary at the rate then in effect. Further, Mr. Branagan’s stock options shall remain exercisable for the entire term of the options.

(ii) the sale, transfer or other disposition of all or substantially all of Petrol’s assets in complete liquidation or dissolution of Petrol other than in connection with a transaction described in (i) above.

On November 1, 2003, Petrol executed an Employment Agreement with Gary Bridwell, wherein Mr. Bridwell agreed to serve as Petrol’s Field Operations Manager. We agreed to pay Mr. Bridwell a starting salary of $10,000 per month and he is entitled to participate in Petrol’s group health insurance and also is entitled to utilize Petrol credit card, which is for the sole use of Company business and is subject to the policies of Petrol covering such matters. On January 11, 2005, we issued 100,000 shares to Mr. Bridwell for completing on year of employment with Petrol. On August 25, 2005, we issued 10,000 shares to Mr. Bridwell as a bonus for his work as field engineering supervisor. On January 1, 2007 Mr. Bridwell terminated his employment with Petrol.

We currently do not have a compensation committee of the board of directors. However, the board of directors intends to establish a compensation committee, which is expected to consist of three inside directors and two independent members. Until a formal committee is established our entire board of directors will review all forms of compensation provided to our executive officers, directors, consultants and employees including stock compensation and loans.

There are no compensatory plans or arrangements, including payments to be received from Petrol, with respect to any person named in Cash Consideration set out above which would in any way result in payments to any such person because of his resignation, retirement, or other termination of such person’s employment with Petrol, or any change in control of Petrol, or a change in the person’s responsibilities following a change in control of Petrol.

Directors of Petrol who are not employees receive compensation of $1,000 for each meeting of the board, as well as travel expenses if required. From time to time, certain directors who are not employees may receive grants of options to purchase shares of our common stock. In addition, we have compensated Suzanne Herring, a member of our board of directors, $60,000 per annum for her services as a director.

The salary administration program for Petrol’s non-contract personnel, which currently consists of 7 people, is administered in an informal manner by Petrol’s CEO. As a result of Petrol’s business as a small oil and gas development company, Petrol’s non-contract personnel are generally on site, in the field employees. Petrol’s salary program is administered in such a way as

to promote productivity. Currently, as a result of the informal nature of the program, it is not designed to accomplish internal equity among personnel. The above principles are applied to all Petrol employees who are non-contract employees (non-executives).

As a result of our lack of a Compensation Committee, our Board of Directors acts in such capacity. Additionally, as a result of our having only one executive officer, our CEO and President, who is under contract as discussed elsewhere herein, we have no formal process for consistent annual reviews of compensation for executives. Our intention is to establish a Compensation Committee, and upon the establishment of the Compensation Committee, we intend for such committee to administer our compensation overview for our executives, and oversee the salary administration program for non-contract employees as administered by our CEO.

At current cash compensation levels, our Board of Directors acting in the capacity of our Compensation Committee does not expect Internal Revenue Service regulations regarding maximum deductibility of executive compensation to have any application to Petrol.

CEO Employment Contract. Effective as of November 2, 2005, Petrol entered into a five (5) year employment contract with Paul Branagan pursuant to which Mr. Branagan serves as Chief Executive Officer of Petrol. Mr. Branagan’s employment contract is discussed in more detail above under the heading “Employment and Other Contracts; Potential Payments Upon Termination or Change in Control.” Mr. Branagan’s annual base salary for the year ended December 31, 2006 was $230,625. Mr. Branagan received no stock option grants in 2006. However, in addition to Mr. Branagan’s base salary, and as part of his agreement with Petrol, Mr. Branagan received $40,511 from his royalty payments and $36,000 in non-accountable expense allowances. As a result of Mr. Branagan’s position as our CEO and President during 2006, and his acting in the capacity of our principal financial officer, we paid Mr. Branagan a $105,000 cash bonus. Additionally, as a result of previously issued options and the extension of options, we accreted $381,384 in stock option value for 2006.

The following table presents information, to the best of our knowledge, about the beneficial ownership of our common stock on April 9, 2007, held by those persons known to beneficially own more than 5% of our capital stock and by our directors and executive officers. The percentage of beneficial ownership for the following table is based on 29,090,926 shares of common stock outstanding as of April 9, 2007.

Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and does not necessarily indicate beneficial ownership for any other purpose. Under these rules, beneficial ownership includes those shares of common stock over which the stockholder has sole or shared voting or investment power. It also includes (unless footnoted) shares of common stock that the stockholder has a right to acquire within 60 days after April 9, 2007 through the exercise of any option, warrant or other right. The percentage ownership of the outstanding common stock, however, is based on the assumption, expressly required by the rules of the Securities and Exchange Commission, that only the person or entity

whose ownership is being reported has converted options or warrants into shares of our common stock.

be deemed to beneficially own as investment advisor, which are held of record by clients of WMC. No such client of WMC is known to have such right or power with respect to more than five percent of this class of securities, except for Spindrift Investors (Bermuda) L.P. and Spindrift partners, L.P.

*The information used for the table of Security Ownership of Certain Beneficial Owners is based on the information reported on the beneficial owners Schedule 13G filings.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

As part of Mr. Branagan’s employment agreement, as amended, we are obligated to pay Mr. Branagan a perpetual 1/100 Over Riding Royalty on production from any wells completed on our leased acreage. For the year ended December 31, 2006, Mr. Branagan earned a total of $40,511 as part of the Over Riding Royalty.

During fiscal 2006, the law firm of Caldwell & Moll, L.C. billed Petrol $71,403 for legal fees and $24,792 in expenses related to services performed on behalf of Petrol. Mr. Moll is a partner in the firm.

During fiscal 2006, Opus Pointe, an accounting services company, was paid $82,500 for fees related to services performed on behalf of Petrol. Ms. Herring is the President of Opus Pointe (now known as Accuity Financial Services, Inc.).

The Board of Directors has analyzed the independence of each director and has concluded that Robert Kite and Duane Fadness are considered independent Directors in accordance with the director independence standards of the American Stock Exchange, and has determined that neither of them has a material relationship with Petrol which would impair his independence from management or otherwise compromise his ability to act as an independent director.

Transactions between related persons (including directors and executive officers of Petrol and their immediate family members) and Petrol or their affiliates are subject to approval by the board of directors. Petrol has no written policy setting forth the procedures for the review and approval of related party transactions. Officers and directors will be regularly reminded of their obligation to seek board approval of any related party transaction or potential conflict of interest. The board will consider all factors that it deems relevant, including the nature of the related party’s interest in the transaction, whether the terms are no less favorable than could be obtained

in arms-length dealings with unrelated third parties, and the materiality of the transaction to Petrol.

The aggregate fees billed for professional services rendered by Weaver & Martin, LLC, for the audit of our annual financial statements and review of the financial statements included in our Form 10-QSB or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements for fiscal years 2006, 2005 and 2004 were $120,737, $105,702 and $98,127, respectively.

The aggregate fees to be billed by Weaver & Martin LLC for professional services to be rendered for tax fees for fiscal years 2006, 2005 and 2004 were $13,650, $10,250 and $5,000, respectively.

The aggregate fees for professional services for audit related services relating to the Registration Statement on Form SB-2 for fiscal years 2006, 2005 and 2004 were $33,725, $30,750 and $20,426, respectively. There were no other fees to be billed by Weaver & Martin LLC for the fiscal years 2006, 2005 and 2004 other than the fees described herein and above.

(6) If greater than 50 percent, disclose the percentage of hours expended on the principal accountant’s engagement to audit the registrant’s financial statements for the most recent fiscal year that were attributed to work performed by persons other than the principal accountant’s full-time, permanent employees.

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

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

We have audited the accompanying consolidated balance sheet of Petrol Oil and Gas, Inc. as of December 31, 2006 and 2005 and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatements. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Petrol Oil and Gas, Inc. as of December 31, 2006 and 2005 and the consolidated results of its operations and cash flows for each of the years in the three–year period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has suffered recurring losses from operations and is dependent upon the continued sale of its securities or obtaining debt financing for funds to meet its cash requirements. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans with regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

				December 31,
				2006		2005

Assets
Current assets:
	Cash			$	5,917,958	$	8,435,203
	Accounts receivable				624,731		613,814
	Prepaid expenses				38,085		-
		Total current assets			6,580,774		9,049,017

Fixed assets:
	Pipeline				5,331,028		2,324,717
	Equipment and vehicles				341,310		291,848
					5,672,338		2,616,560
	Less accumulated depreciation				471,600		171,657
Fixed assets, net					5,200,738		2,444,903

Other assets:
	Oil and gas properties using full cost accounting:
		Properties not subject to amortization			1,210,174		954,002
		Properties subject to amortization			21,856,363		13,662,783
	Capitalized loan costs, net				662,511		816,329
	Deposits				1,932		-
	Derivative asset				974,752		-
			Total other assets		24,705,732		15,433,114
				$	36,487,244	$	26,927,034

Liabilities and Stockholders’ Equity
Current liabilities:
	Accounts payable			$	462,188	$	1,374,938
	Accrued liabilities				430,190		151,168
	Short-term derivative liability				-		1,183,685
	Current portion of long term debt				14,193,588		2,101,111
			Total current liabilities		15,085,966		4,810,902

Asset retirement obligation					907,797		749,618
Long-term derivative liability					58,133		512,931
Long-term debt, less current portion					13,169,895		12,375,007
					14,135,825		13,637,556
Commitments and contingencies
Stockholders’ Equity:
	Preferred stock, $0.001 par value, 10,000,000
		shares authorized, no shares issued and
		outstanding			-		-
	Common stock, $0.001 par value, 100,000,000 shares authorized
		29,084,597 and 26,890,083 shares issued and outstanding at
		December 31, 2006 and December 31, 2005, respectively			29,084		26,889
	Stock bought or for services not issued, 6,329 and 740,449 at
		December 31, 2006 and December 31, 2005, respectively			6		740
	Unamortized cost of stock, warrants & options issued for services				(1,461,747)		(2,380,365)
	Prepaid share-based compensation				(47,600)		-
	Subscription receivable				-		(75,000)
	Additional paid-in capital				28,555,484		25,534,114
	Other comprehensive income (loss)				916,619		(1,696,616)
	Accumulated (deficit)				(20,726,393)		(12,931,186)
					7,265,453		8,478,576

				$	36,487,244	$	26,927,034

			For the Year Ended
			December 31,
			2006		2005		2004


Revenue
	Oil and gas activities		$	7,489,401	$	6,040,957	$	866,924
	Royalties and overrides			956,603		796,151		-

Gross profit				6,532,798		5,244,806		866,924

Expenses:
	Direct costs			2,908,693		3,084,494		221,339
	Pipeline costs			910,739		230,944		-
	General and administrative			1,649,028		1,616,334		607,617
	Professional and consulting fees			1,957,177		2,577,970		1,906,036
	Salaries and wages			262,436		264,049		225,745
	Salaries and wages - related party			753,009		234,636		166,667
	Depreciation, depletion and amortization			2,811,185		1,392,342		213,475
	Acquisition costs			-		-		654,000
		Total expenses		11,252,267		9,400,769		3,994,879

Net operating (loss)				(4,719,469)		(4,155,963)		(3,127,955)

Other income (expense):
	Interest expense			(3,075,739)		(1,807,833)		(1,395,952)

Net (loss)			$	(7,795,208)	$	(5,963,796)	$	(4,523,907)


Weighted average number of
	common shares outstanding - basic and fully diluted			28,770,494		25,632,220		20,647,542

Net (loss) per share - basic and fully diluted			$	(0.27)	$	(0.23)	$	(0.22)

				Stock	Unamortized		Prepaid
			Additional	Bought or	Cost of	Other	Share-based/		Total
	Common Stock		Paid-in	for Services	Stock Issued	Comprehensive	Subscription	Accumulated	Stockholders’
	Shares	Amount	Capital	Not Issued	For Services	Loss	Receivable	Deficit	Equity

Balance, December 31, 2003	17,247,466	$ 17,247	$ 4,630,713	$ 160	$ (1,000)	$ -	$ -	$(2,443,483)	$ 2,203,637

Shares issued for services	413,861	415	904,085	-	-	-	--	-	904,500
Shares issued	160,000	160	-	(160)	-	-	--	-	-
Shares issued for asset acquisition	765,000	765	764,235	-	-	-	--	-	765,000
Warrants and options issued for services	-	-	548,600	-	-	-	--	-	548,600
Shares for services not yet issued	-	-	200,873	126	-	-	-	-	200,999
Shares for acquisition not yet issued	-	-	94,950	50	-	-	--	-	95,000
Options exercised	1,350,000	1,350	836,150	-	-	-	--	-	837,500
Shares returned from collateral	(1,000,000)	(1,000)	-	-	1,000	-	--	-	-
Shares held by lender as collateral	50,000	50	-	-	(50)	-	-	-	-
Shares issued for cash	5,633,333	5,633	6,135,567	-	-	-	-	-	6,141,200
Beneficial conversion of convertible stock	-	-	1,013,000	-	-	-	-	-	1,013,000
Warrants issued in financing	-	-	2,072,534	-	-	-	-	-	2,072,534
Other comprehensive loss	-	-	-	-	-	(229,435)	-	-	(229,435)
Net loss	-	-	-	-	-	-	-	(4,523,907)	(4,523,907)
Balance, December 31, 2004	24,619,660	24,620	17,200,707	175	(50)	(229,435)	-	(6,967,390)	10,028,627

Shares issued for services	252,785	252	537,747	-	-	-	-	-	537,999
Warrants and options issued for services	-	-	803,050	-	(537,230)	-	-	-	265,820
Warrants issued in financing	-	-	1,376,803	-	-	-	-	-	1,376,803
Shares issued for debt conversion	1,297,565	1,297	1,945,048	-	-	-	-	-	1,946,345
Warrants exercised	550,073	550	561,825	125	-	-	(75,000)	-	487,500
Shares authorized and unissued for services	-	-	93,468	54	-	-	-	-	93,522
Shares used to acquire property	10,000	10	1,108,529	546	-	-	-	-	1,109,085
Shares previously authorized now issued	160,000	160	-	(160)	-	-	-	-	-
Options granted for services - related party		-	1,906,937	-	(1,843,085)	-	-	-	63,852
Other Comprehensive loss	-	-	-	-	-	(1,467,181)	-	-	(1,467,181)
Net loss	-	-	-	-	-	-	-	(5,963,796)	(5,963,796)
Balance, December 31, 2005	26,890,083	26,889	25,534,114	740	(2,380,365)	(1,696,616)	(75,000)	(12,931,186)	8,478,576

				Stock	Unamortized		Prepaid
			Additional	Bought or	Cost of	Other	Share-based/		Total
	Common Stock		Paid-in	for Services	Stock Issued	Comprehensive	Subscription	Accumulated	Stockholders’
	Shares	Amount	Capital	Not Issued	For Services	Loss	Receivable	Deficit	Equity
Shares issued for services	95,317	95	165,505	-	-	-	(47,600)	-		118,000
Warrants and options issued for services	-	-	145,252	-	-	-	-	-		67,252
Warrants granted for financing			661,778	-	-	-	-	-		661,778
Shares issued for interest	135,533	136	203,164	-	-	-	-	-		203,300
Shares issued for debt conversion	609,020	609	912,921	-	-	-	-	-		913,530
Warrants exercised	205,000	205	241,670	-	-	-	-	-		241,875
Subscription cancelled for services	-	-	-	-	-	-	75,000	-		75,000
Shares authorized and unissued for services	-	-	14,994	6	-	-	-	-		15,000
Shares used to acquire property	409,195	409	676,088	-	-	-	-	-		676,498
Shares previously authorized now issued	740,449	740	-	(740)	-	-	-	-		-
Amortization of options for services	-	-	-	-	918,618	-	-	-		996,618
Other Comprehensive loss	-	-	-	-	-	2,613,235	-	-		2,613,235
Net loss	-	-	-	-	-	-	-	(7,795,208)		(7,795,208)
Balance, December 31, 2006	29,084,597	$ 29,084	$28,555,486	$ 6	$(1,461,747)	$ 916,619	$ (47,600)	$(20,726,394)		$ 7,265,454

			For the Year Ended
			December 31,
			2006		2005		2004
Cash flows from operating activities
Net (loss)			$	(7,795,208)	$	(5,963,796)	$	(4,523,907)
Depreciation, depletion and amortization				2,811,185		946,585		383,987
Warrant accretion				1,295,726		943,800		-
Accretion of asset retirement obligation				71,779		51,041		-
Shares issued for interest				203,300		627,093		-
Stock subscriptions for services				75,000		-
Shares issued for asset acquisition				-		-		654,000
Stock, warrants and options issued for services				1,196,870		1,505,140		1,557,598
Beneficial conversion				-		-		1,013,000
Adjustments to reconcile net (loss) to cash
	used in operating activities:
		Accounts receivable		(10,917)		(300,832)		(312,982)
		Prepaid and other assets		(38,085)		27,305		(11,526)
		Accounts payable		(912,750)		912,786		194,081
		Accrued liabilities		279,023		(114,463)		203,513
		Accrued liabilities - related party		-		(270,000)		270,000
Net cash used in operating activities				(2,824,077)		(1,635,341)		(572,236)

Cash flows from investing activities
	Purchase of fixed assets			(3,055,781)		(884,748)		(1,685,214)
	Additions to oil and gas properties			(9,224,470)		(1,521,979)		(10,241,023)
	Purchase of oil and gas leases			(256,172)		(140,114)		(367,506)
	Additions to deposits			(1,933)		-		-
	Release of restricted cash			-		852,346		(852,346)
	Investments			-		-		184,222
Net cash used in investing activities				(12,538,356)		(1,694,495)		(12,961,867)

Cash flows from financing activities
	Additions to loan fees			(563,634)		-		-
	Amortized loan fees			-		(79,329)		(707,500)
	Proceeds from loans payable			15,000,000		10,026,880		8,000,000
	Payments on notes payable			(1,833,053)		(462,952)		(4,050)
	Proceeds from sales of common stock			-		-		6,978,700
	Proceeds from exercising of warrants			241,875		487,500		-
Net cash provided from financing activities				12,845,188		9,972,099		14,267,150

Net increase (decrease) in cash				(2,517,245)		6,642,263		733,047
Cash - beginning				8,435,203		1,792,885		1,059,838
Cash - ending			$	5,917,958	$	8,435,148	$	1,792,885

Supplemental disclosures:
	Interest paid		$	2,505,161	$	182,956	$	26,685
	Income taxes paid			-		-		-

Non-cash transactions
	Stock issued for oil & gas properties		$	676,497	$	1,108,538	$	859,950
	Stock issued for debt conversions			1,116,830		1,946,347		-
	Stock, warrants and options issued for services			1,196,870		4,718,997		2,621,134
	Asset retirement obligation			86,400		51,041		-

The Company was organized on March 3, 2000, under the laws of the State of Nevada, as Euro Technology Outfitters (Euro). On August 19, 2002 Euro acquired, in an asset purchase agreement, land leases and accumulated expenditures and assumed liabilities from Petrol Energy, Inc. On August 20, 2002, the Company amended its Articles of Incorporation to rename the Company, Petrol Oil and Gas, Inc. and increased the authorized capital stock to 100,000,000 shares of Common Stock, $0.001 par value, and 10,000,000 shares of Preferred Stock, $0.001 par value.

We are now engaged in the exploration, development, production and marketing of oil and natural gas. The Company’s primary objective is the development of Coalbed Methane (CBM) gas production projects. We have focused our efforts to eastern Kansas and western Missouri where leases were acquired that appeared geologically suitable for CBM exploration.

Our consolidated financial statements include the accounts of our wholly owned subsidiaries, Neodesha Pipeline, LLC and Coal Creek Pipeline, LLC after elimination of intercompany transactions.

The preparation of consolidated financial statements in conformity with 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We regularly review collectability and establish or adjust an allowance for uncollectible accounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. There were no reserves for uncollectible amounts in the periods presented.

In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004) “Share-Based Payment” (“SFAS No. 123R”), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB Opinion 25. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on the fair values beginning with the first interim period in fiscal year

2006. The pro forma disclosures previously permitted under SFAS No. 123 are no longer an alternative to financial statement recognition.

Common stock, warrants and options issued for services by non-employees are accounted for based on the fair market value at the date the services are performed. If the services are to be performed over a period of time the value is amortized over the life of the period that services are performed.

We account for our stock option plan in accordance with the provisions of SFAS No. 123R, “Accounting for Stock Based Compensation”. The cost of options are included as an expense when the options are vested.

We account for income taxes under SFAS 109, Accounting for Income Taxes. The asset and liability approach requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax basis of assets and liabilities. The provision for income taxes differ from the amounts currently payable because of temporary differences in the recognition of certain income and expense items for financial reporting and tax reporting purposes.

At December 31, 2006 and 2005, our financial instruments consist of accounts receivable and long-term debt. Interest rates currently available to us for long-term debt with similar terms and remaining maturities are used to estimate fair value of such financial instruments. Accordingly, since interest rates on substantially all of our debt are variable, market based rates, the carrying amounts are a reasonable estimate of fair value.

SFAS No. 128, Earnings Per Share. This standard requires dual presentation of basic and diluted earnings per share on the face of the income statement for all entities with complex capital structures and requires a reconciliation of the numerator and denominator of the diluted loss per share computation.

Potentially issuable shares of common stock pursuant to outstanding stock options and warrants are excluded from the diluted computation, as their effect would be anti-dilutive.

We consider all highly liquid investment instruments purchased with remaining maturities of three months or less to be cash equivalents for purposes of the consolidated statements of cash flows and other statements. We maintain cash on deposit in non-interest bearing accounts, which, at times, exceed federally insured limits. We have not experienced any losses on such accounts and believe we are not exposed to any significant credit risk on cash and equivalents.

The Company follows the “sales” (takes or cash) method of accounting for oil and gas revenues. Under this method, we recognize revenues on production as it is taken and delivered to its purchasers. The volumes sold may be more or less than the volumes we are entitled to base our ownership interest in the property. These differences result in a condition known in the industry as a production imbalance. Our crude oil and natural gas imbalances are not significant.

Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt on an interest method of accretion over the estimated life of the debt.

Property and equipment are recorded at cost. Depreciation is on a straight-line method using the estimated lives of the assets (5-30 years). Expenditures for maintenance and repairs are charged to expense.

We follow the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development are capitalized.

All capitalized costs included in the estimated future costs to develop proved reserves, are amortized on the unit-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonment’s of oil and gas properties are charged to the full cost pool and amortized.

Under the full cost method, the net book value of oil and gas properties are subject to a “ceiling”. The ceiling is the estimated after-tax future net revenue from proved oil and gas properties, discounted at 10% per annum plus the lower of cost or fair market value of unproved properties. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except for changes that are fixed and determinable by existing contracts. The excess, if any, of the net book value above the ceiling is written off as an expense.

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized as income.

Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value. The carrying value of the assets is then reduced to their estimated fair value which

is usually measured based on an estimate of future discounted cash flows. No adjustments were necessary during the periods presented.

We adopted the Statement of Financial Accounting Standards No. 143, “Asset Retirement Obligations” (“SFAS 143”) which requires us to recognize an estimated liability for the plugging and abandonment of our oil and gas wells and associated pipelines and equipment. The liability and the associated increase in the related long-lived asset are recorded in the period in which our asset retirement obligation (“ARO”) is incurred. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.

The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free rate.

Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free rate or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, we recognize a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs. .

We substantially sell all oil and gas production to two customers. In 2006 and 2005 the two largest customers accounted for 75% and 12% and 81% and 18%, of sales, respectively. In 2004 one customer accounted for 83% of all sales.

We seek to reduce our exposure to unfavorable changes in natural gas prices by utilizing energy swap contracts (effectively fixed price contracts). We have adopted SFAS 133, as amended by SFAS 138, Accounting for Derivative Contracts and Hedging Activities. It requires that all derivative instruments be recognized as assets or liabilities in the statement of financial position, measured at fair value. Accounting for changes in the fair value of the derivative depends on the intended use of the derivative and the resulting designation. For derivatives that are designated as cash flow hedges changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings.

Although our fixed price contracts may not qualify for special hedge accounting treatment from time to time under specific guidelines of SFAS 133, we refer to these contracts as hedges inasmuch as this was the intent when such contracts were executed, the characterization is consistent with the actual economic performance of the contracts, and we expect the contracts to continue to mitigate our commodity price risk in the future. The accounting for the contracts is consistent with the requirements of SFAS 133.

We have established the fair value of all derivative instruments using estimates determined by using established index prices and bases adjustments. The values reported in the financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.

In September 2006, the Securities and Exchange Commission staff (“SEC”) issued SAB 108. SAB 108 was issued to provide consistency to how companies quantify financial statement misstatements. SAB 108 establishes an approach that requires companies to quantify misstatements in financial statements based on effects of the misstatement on both the consolidated balance sheet and statement of operations and the related financial statement disclosures. Additionally, companies must evaluate the cumulative effect of errors existing in prior years that previously had been considered immaterial. We adopted SAB 108 in connection with the preparation of our annual financial statements for the year ended December 31, 2006 and found no adjustments necessary.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements, rather, its application will be made pursuant to other accounting pronouncements that require or permit fair value measurements. SFAS No.157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The provisions of SFAS No. 157 are to be applied prospectively upon adoption, except for limited specified exceptions. We are evaluating the requirements of SFAS No. 157 and do not expect the adoption to have a material impact on our Consolidated Balance Sheet or Statement of Operations.

In June 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”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006 and will be adopted by us on January 1, 2007. We have not been able to complete our evaluation of the impact of adopting FIN 48 and as a result, are not able to estimate the effect the adoption will have on our financial position and results of operations, including our ability to comply with current debt covenants.

Certain reclassifications have been made to prior periods to conform to current presentation.

Our financial statements are prepared using generally accepted accounting principles applicable to a going concern, which contemplates the realization of assets and liquidation of liabilities in the normal course of business. Our ability to continue as a going concern is dependent upon us

obtaining additional sources of capital or borrowings until the time when we are able to attain future profitable operations. The accompanying financial statements do not include any adjustments that might be necessary should the company be unable to continue as a going concern.

As of December 31, 2006 and 2005, there were 6,329 and 740,449 shares unissued, respectively. The shares that were not issued at December 31, 2005 were issued in 2006.

We entered into a geologist/technical advisor consulting agreement with Mr. William Stoeckinger. The agreement was for a one-month term and Mr. Stoeckinger received 20,000 shares valued at $20,000. The fair market value of the stock was determined based on the price that we were selling shares to our investors. Professional and consulting expense was charged $20,000 in 2004.

On January 14, 2004, we entered into a twelve-month consulting agreement with Consulting Solutions whereby Consulting solutions would provide introduction to international strategic alliance partners for investment in drilling activities related to CBM production. At December 31, 2004, we issued 35,000 shares in the name of Fidelity Insurance Co. on behalf of Consulting Solutions for services provided per the consulting agreement. The value of the stock as determined by the market price of our stock on the day of the agreement was $73,500 and this was recorded as professional and consulting fee expense.

On January 15, 2004, we agreed to exchange 765,000 shares of our stock to Mr. John Haas, Mr. Mark Haas and Mr. W.B. Mitchell, principals of CBM Energy, Inc. for oil and gas mineral leases covering approximately 36,000 acres and title to approximately 10 existing wells. The value of the transaction is $765,000. $31,000 of value was assigned to property not subject to amortization based on the remaining lease cost of each leased acre. $80,000 of value was assigned to property subject to amortization based on the fair market value of the test wells on the leased property. The remaining $654,000 was expensed in January 2004.

On February 9, 2004, we agreed to issue 10,000 shares of common stock to Joseph Blankenship. The value of the stock of $10,000 was recorded as a professional and consulting fees expense. The shares were issued to Mr. Blankenship in 2005.

On May 3, 2004, we issued 100,000 shares of our common stock to CPA Directed Investments (CDI) pursuant to a secured promissory note agreement dated May 5, 2004. CDI will return 50,000 shares for cancellation at such time the loan and interest are paid in full. The remaining 50,000 shares will be retained by CDI as a loan fee. Due to the nature of this being a short-term loan the loan fee was expensed. The amount was determined based on the market value of our stock on the date of the agreement and totalled $132,500. The par value ($50) of the 50,000 shares held as collateral was recorded as unamortized cost of stock issued for services until such time as the shares are returned.

On June 17, 2004, we issued 120,000 shares of our common stock to XXR Consulting Inc. pursuant to a consulting agreement we executed on June 4, 2004. The value of the stock as determined by the market price of our stock on the day of the agreement was $276,000 and was recorded as professional and consulting fee expense.

On June 15, 2004, we agreed to a consulting agreement with ECON Investor Relations, Inc. The monthly fee is $10,000 of which $6,000 is payable in stock. The agreement is for one year with either party able to terminate the agreement based on 30 days written notice. Stock earned but not issued to the consultant at December 31, 2004 was recorded at par value.

On September 20, 2004, we entered into an agreement with Haas Oil Group whereby we agreed to issue 50,000 shares of common stock in exchange for 100% working interest in certain leases that Hass owned. The shares were valued at $1.90 per share, which was the trading price of our common stock on September 20, 2004 the date the agreement was signed. As of December 31, 2004 the shares were not issued.

On November 1, 2004 we recorded as additional compensation $152,000 that represented the market value (as determined based on the price our shares were trading on that day) of 100,000 shares of our common stock that was earned by Mr. Gary Bidwell. The shares were not issued as of December 31, 2004.

On December 2, 2004, we issued 90,000 shares of common stock to Hard Funding, Inc. pursuant to the twelve-month financial consulting agreement entered into on January 14, 2004. The value of the stock as determined by the market price of our stock on the day of the agreement was $189,000 and was recorded as professional and consulting fee expense.

On December 16, 2004, we issued 90,000 shares of common stock to CEOcast pursuant to the consulting agreement entered into on June 2004. The value of the stock as determined by the market price of our stock on the day of the agreement was $152,100 and was recorded as professional and consulting fee expense.

We sold 5,633,333 shares of our common stock in 2004. Each share was sold for $1.20 and it included a warrant to purchase an additional share of common stock for a price of $1.50 per share expiring on September 8, 2007. The proceeds raised totaled $6,760,000. The proceeds were offset by direct costs relating to commissions paid, totaling $479,800, legal fees of $131,500 and other costs of $7,500. We also issued 845,000 warrants as additional commission to Energy Capital Solutions (see options and warrants below). The value assigned to the warrants would normally be recorded as additional paid-in capital, however, since this was a cost of the offering there was no additional paid-in capital. The net amount received from the sale was $6,141,200.

A supplier has agreed to be paid in stock for 10% of any invoice. Stock earned but not issued to the supplier at December 31, 2004 was recorded at par value.

On January 11, 2005, we awarded Mr. David Polay 50,000 shares and Mr. LoCascio 10,000 shares of our common stock for services. The value of the stock was determined based on the closing value of its stock on the date the stock was issued. We recorded $141,000 as professional fee expense.

On January 11, 2005, we issued 60,000 shares of its common stock in lieu of cash compensation to Russell A. Frierson for land and administrative support rendered to the Company. The value of the stock was determined based on the closing value of its stock on the date the stock was issued. We recorded $141,000 as professional fee expense.

We entered into consulting agreements with CEOcast, Inc., in 2005 wherein we agreed to issue 100,000 shares of our common stock to CEOcast. The value of the stock was determined based on the closing value of the stock on the date the stock was issued. We recorded $186,800 as professional fee expense

On August 8, 2005, we issued 22,785 shares of our common stock (valued at $54,000) to ECON Investor Relations, Inc. pursuant to its consulting agreement.

On August 25, 2005, we issued 10,000 shares of our common stock to Gary Bridwell as a bonus for his work as field engineering supervisor. The value of our common stock on the day of the bonus was used to record the wage expense of $15,200.

During fiscal 2005 Laurus Master Fund Ltd. Converted $1,370,294 of principal and $576,053 of accrued interest under the convertible term note. Pursuant to the conversion rate of $1.50 they were issued 1,297,565 shares of common stock.

In connection with our financing we agreed to issue 50,000 shares of our common stock to Draper & Associates. The value of our common stock on the day the services were agreed to was used to record a loan fee of $90,000. The shares were not issued as of December 31, 2005.

A supplier agreed to take our common stock in lieu of cash payments. The liability was $3,522. The shares were not issued as of December 31, 2005.

We purchased an operating asset in exchange for 10,000 shares of our common stock. The value of our common stock on the day of the purchase was used to record a value of $16,400.

We acquired working interests in producing wells for 546,342 shares of our common stock. The value of our stock on the day of the acquisition was used to value the purchase at $1,092,684. The shares were not issued as of December 31, 2005.

During fiscal 2006, Laurus Master Fund Ltd. Converted $913,530 of principal and $203,300 of accrued interest under the convertible term note. Pursuant to the conversion rate of $1.50 they were issued 744,553 shares of common stock.

On February 16, 2006, we issued 40,334 shares of our common stock in exchange for working interest in producing wells valued at $60,500.

On March 31, 2006, we expensed $75,000 subscription receivable in exchange for services rendered in connection with investor relations services.

On May 9, 2006, we issued 368,861 shares of our common stock for the purchase of working interests in producing wells valued at $615,997.

During the year ended December 31, 2006, we issued 95,317 shares of our common stock for various services received. The Company recorded an expense in the amount of $118,000, the fair value of the underlying shares. The remaining value of the services at December 31, 2006 was $47,600 and this was recorded as prepaid share-based compensation and will be amortized over the term of the underlying agreement.

At December 31, 2006, we authorized the issuance of 6,329 shares of our common stock pursuant to our 2004 investor relations agreement. The agreement was cancelled as of October 31, 2006. The Company recorded an expense in the amount of $15,000, the fair value of services rendered. As of December 31, 2006, the shares were un-issued.

All values of options and warrants were determined based on the Black-Scholes pricing model.

The weighted average of the assumptions used to value options and warrants in 2004 were: Interest rate-2.32%, Days to expiration-936, Stock price $1.41, Strike price-$1.39, Volatility-23%, Yield-0%.

The weighted average of the assumptions used to value options and warrants in 2005 were: Interest rate-5.62%, Days to expiration-1,797, Stock price $1.94, Strike price-$1.99, Volatility-49%, Yield-0%.

The weighted average of the assumptions used to value options and warrants in 2006 were: Interest rate-6.43%, Days to expiration-1,689, Stock price $1.70, Strike price-$1.74, Volatility-82%, Yield-0%.

The Board of Directors on December 16, 2002 adopted the 2002 stock option plan for 3,000,000 shares. On December 20, 2005 the Board approved the 2006 stock option plan for 3,000,000 shares. At December 31, 2005 the options issued to Mr. Branagan are part of the 2006 plan.

On February 9, 2004, we granted Joseph Blankenship an option to purchase 50,000 shares at $2.50 per share for the first 25,000 shares and $4.00 for the remaining 25,000 shares. The option was granted pursuant to the Research Agreement. The term of the option was for two years. The value of the options was $200 and was recorded as a professional and consulting fees expense.

On March 1, 2004, we issued 100,000 stock options with an exercise price of $1.25 per share and 200,000 stock options with an exercise price of $1.50 per share to Mr. William Burk. Mr. Burk has performed consulting services for the Company. The options expired in three years. The value of the options was $38,500 and this was recorded as a professional and consulting fees expense.

On March 16, 2005, we executed an agreement with CSC Group, wherein Steve Cochennet, (an Advisory Board Member) President of CSC Group, agreed to provide the Company with services to further the Company’s long-term strategy. The term of the agreement began on January 1, 2005. The Company agreed to pay Mr. Cochennet $5,000 per month plus grant 150,000 options to CSC Group at $2.04 per share for a period of five years. Mr. Cochennet will also receive 3% of any debt facility or mezzanine financing he puts in place prior to December 31, 2005. The value of the options was $138,795 and was recorded as professional fee expense.

On March 18, 2005, we executed an agreement with Robert Howell, (an Advisory Board Member) wherein Mr. Howell agreed to provide the Company with services on specified assignments as needed by the Company. The term of the agreement is for three months and began on February 1, 2005. We agreed to compensate Mr. Howell $10,000 for each month plus pay for all reasonable business and travel expenses, and grant Mr. Howell 125,000 options to purchase common stock at $2.33 per share. The options are fully vested and will have five years in which to exercise them. If Mr. Howell is involved in finding sources of debt for the Company, he will work with Mr. Cochennet and be paid an additional fee by Mr. Cochennet. The value of the warrants was $86,825 and was recorded as professional fee expense.

On May 9, 2005, we entered into an agreement with an employee to provide services to the Company. As part of the agreement the employee will receive 60,000 options vesting 20,000 per year at $2.33 per share expiring in five years. The value of the options was $40,200. The employee left the Company before any of the options were vested and the value was charged to wage expense.

On October 29, 2005, we entered into an employment agreement with Mr. Branagan, the CEO of the Company. We granted Mr. Branagan 500,000 options at an exercise price of $1.75 per share. The options have a 5-year term. The value of the options was $509,707 and was recorded as unamortized cost of stock issued for services. The cost will be amortized over the five-year contract period. We also extended Mr. Branagan’s previously issued options (250,000 options with the following strike prices-$0.50, $1.00, $1.50, $2.00, and $2.50 for a total of 1,250,000 options) for an additional five-year period. The additional value of extending these options was $1,397,230 and recorded as Unamortized cost of stock, warrants, and options issued for services that will be amortized over the five-year period of the contract. We amortized as wage expense $63,852 in 2005.

On December 20, 2005, we entered into an agreement with Steve Cochennet whereby we granted Mr. Cochennet 150,000 options at a strike price of $1.75 and 150,000 at strike price of $2.00 for a six-month term. We also extended Mr. Cochennet’s existing $1.50 and $2.50 warrants for an additional 4 years. The value of the options and warrants was $537,230 and was recorded as unamortized cost of stock, warrants and options issued for services and will be amortized over the six-month term of the agreement which begins in fiscal 2006.

On January 1, 2006, we entered into a one year agreement with R. J. Falkner whereby we granted Mr. Falkner 110,000 options at a strike price of $1.76 exercisable for a period of thirty-six months. The value of the option was $104,004.

On June 30, 2006, we extended the term of options previously issued to a consultant and have recorded an expense in the amount of $30,910.

On September 15, 2006, we granted CSC Group 25,000 options at a strike price of $1.75 exercisable for a period of twenty-four months. The value of the option was $10,338 and was recorded as consulting expense.

On January 15, 2004, we entered into an agreement with Mr. John Haas, Mr. Mark Hass and Mr. W.B. Mitchell whereas we would be allowed six months access to approximately 10,000 acres of leased mineral rights for the purpose of exploring, and evaluating gas production. Mr. John Haas agreed to join the Board of Directors of the Company. Mr. Mark Hass agreed to be a project manager and consultant for the Company. Mr. W.B. Mitchell agreed to provide consulting support for lease/land acquisitions. Each of the three individuals received 600,000 stock warrants (1,800,000 total) to purchase shares at a price of $1.20 per share; 400,000 stock warrants (1,200,000 total) to purchase shares at a price of $1.50 per share; and 300,000 stock warrants (900,000 total) to purchase shares at a price of $2.00 per share. The warrants expire on July 15, 2006. The value of the warrants was $420,700 and was recorded in January 2004 as a professional and consulting fee expense.

On February 18, 2004, we granted to CSC Group, LLC a stock warrant giving CSC the right to purchase 200,000 shares of our common stock. The number of shares, exercise price and term of the warrants shall be: (i) 100,000 shares at $1.50 per share for a term of two years; and (ii) 100,000 shares at $2.50 per share for a term of two years. The value of the warrants was $7,400 and was recorded as a professional fees expense. The warrants were subsequently extended for an additional 4 years.

In connection with the sale of 5,633,333 shares of common stock in 2004 each share purchased included a warrant to purchase an additional share of common stock for a price of $1.50 per share expiring on September 8, 2007.

On October 7, 2004, we issued 845,000 warrants to Energy Capital Solutions in connection with stock sales. The warrants are for the purchase of common stock at a price of $1.35 per share and expire October 29, 2009. The value of the warrants was $447,850. The warrants were part of the cost of the offering and therefore no entry was made to additional paid-in capital.

On October 28, 2004, we issued 5,333,333 warrants to Laurus Master Fund, Ltd., in connection with the convertible note agreement entered into on the same day. Pursuant to the agreement, Laurus Master Fund was issued 3,520,000 warrants to purchase common stock for a price of $2.00 per share expiring on October 28, 2009 and an additional 1,813,333 warrants to purchase common stock at a price of $3.00 per share expiring on October 28, 2004. The value of the warrants was $2,072,534, which was offset against the long-term liability and will be accreted to interest expense over the life of the loan. We issued 100,000 warrants to Draper & Associates in connection with the financing arrangement. These warrants are for the purchase of common stock at a price of $2.00 per share and will expire on October 29, 2007. The value of the warrants was $38,860 and was recorded as capitalized loan costs and will be amortized over a three-year period.

On January 28, 2005, in exchange for delaying its monthly principal payment until June 2005 on the note due to Laurus Master Fund, we issued Laurus 666,667 warrants at an exercise price of $2.50 and 333,333 warrants at an exercise price of $3.00. The value of the warrants was $549,000 and was recorded as professional fee expense.

On October 31, 2005, we granted Laurus Master Fund 1,000,000 warrants at a strike price of $2.00 per share for a five-year period in connection with the new note. The value of the warrants was $827,003. The value will be accreted to interest expense over the estimated term of the loan.

In 2005, 425,000 warrants were exercised at an average price of $1.32. Included in subscription receivable is $75,000 due on the exercise of warrants. There were 845,000 warrants exercised on a cashless basis for 250,073 shares. At December 31, 2005 125,000 shares were not issued for exercised warrants.

On February 22, 2006, we issued 100,000 shares of our common stock for the exercise of warrants in exchange for cash totaling $150,000.

On April 1, 2006 we granted Laurus Master Fund 200,000 warrants at a strike price of $1.80 per share for a five-year period in connection with the new note. The value of the warrants was $265,015. The value will be accreted to interest expense over the estimated term of the loan.

On April 28, 2006, we issued 105,000 shares of our common stock for the exercise of warrants in exchange for cash totaling $91,875.

On May 31, 2006, we granted Laurus Master Fund 400,000 warrants at a strike price of $1.65 per share for a five-year period in connection with the new note. The value of the warrants was $396,763. The value will be accreted to interest expense over the estimated term of the loan.

On April 2, 2004, we entered into a 39-month lease for office space in Las Vegas, Nevada. The monthly lease payment is $3,448.40. On April 13, 2006, we entered into an additional 24-month lease for office space located in Kansas. The monthly lease payment is $1,700. Total rent expense for 2006 and 2005 was approximately $56,780 and $57,000 respectively. Future minimum rent payments are 2007-$34,200 and 2008-$20,400.

On October 2004 we issued an $8,000,000 secured convertible term note (“Note”) to Laurus Master Fund, Ltd. (“Laurus”). The Note is convertible into shares of our common stock at an fixed conversion price of $1.50 per share. Pursuant to this agreement, we also issued to Laurus a warrant (“Warrant”) to purchase up to 5,333,333 shares of our common stock, of which 3,520,000 shares will have an exercise price of $2.00 and 1,813,333 shares will have an exercise price of $3.00.

There was a beneficial conversion feature to the convertible note. On the day the note was issued the difference between the conversion price of the note and the market value based on the current trading price of our common stock was $1,103,000. The beneficial conversion was recorded as interest expense for the year ended December 31, 2004.

The Laurus Note has a term of three years and accrues interest at the prime rate plus 3% per year. During 2006 interest ranged from 11.0% to 11.75%. At December 31, 2006 the rate was 11.5%. Interest ranged from 8.25% to 10.5 % for the year ended at December 31, 2005 with the rate being 10.5% at December 31, 2005 and 8% to 8.25% for the year ended December 31, 2004 and 8.25% at December 31, 2004. The Note is secured by substantially all our assets. .

Interest on the unrestricted principal amount is payable monthly, in arrears, on the first business day of each calendar month until the maturity date. Under the terms of the Note, the monthly interest payment and the monthly principal payment are payable either in cash at 102% of the respective monthly amortization amounts or, if certain criteria are met, in shares of our common stock. The minimum monthly principal repayment of $228,000 together with any accrued or unpaid interest, commenced on December 1, 2004, and will continue through the maturity date.

The principal criteria for the monthly payments to be made in shares of our common stock include:

We may prepay the non-restricted and the restricted facility of the Note at a time by paying 130% of the amortizing principal amount then outstanding, together with accrued but unpaid interest thereon. Upon an event of default under the Note, Laurus may demand repayment of the outstanding principal balance at a rate of 130% of the Note plus any accrued interest.

On a month-by-month basis, if we register the shares of common stock issuable upon conversion of the Note and upon exercise of the Warrant on a registration statement declared effective by the Securities and Exchange Commission, and the market price of our common stock for five consecutive trading days exceeds the conversion price by at least 25%, then the interest rate on the Note for the succeeding calendar month shall be reduced by 1% for every 25% increase in the market price of our common stock above the conversion price of the Note, but in no event shall the interest rate be less than 7.5%.

Laurus also has the option to convert all or a portion of the Note into shares of our common stock at any time, subject to limitations described below, at a conversion price of $1.50 per share. Laurus is limited on its ability to convert the Note or exercise the warrants if the conversion or exercise would cause the shares then held by Laurus to exceed 4.99% of our outstanding shares of common stock unless there has been an event of default or Laurus provides us with 75 days prior notice.

In October 2005, we borrowed $10,000,000 from Laurus on a secured term note. The interest on the note is prime plus 3.25%. Principal payments will begin in May, 2006 in an amount based on 80% of net revenues as defined in the note agreement that principally consists of net revenue on new producing wells. The loan will mature on October 31, 2008. Interest rates ranged from 11% to 11.75% during fiscal 2006. At December 31, the rate was 11.5%

On March 31, 2006, we borrowed $5,000,000 from Laurus under the credit facility provided in October 2005. Under the terms of the agreement the Company issued a Secured Term Note (the “Note”) in the aggregate principal amount of $5 million. The Note has a three-year term and bears an interest rate equivalent to the “prime rate” published by the Wall Street Journal from time to time plus 3.25%, subject to a floor of 10% and a ceiling of 14% per annum. Concurrently with the agreements listed above, the Company amended and restated its previous $10 million Secured Term Note dated October 31, 2005 with Laurus Funds. Interest rates ranged from 11% to 12% during fiscal 2006. At December 31, the rate was 12%

On May 31, 2006, we borrowed $10,000,000 from Laurus under the credit facility provided in October 2005. Under the terms of the agreement the Company issued a Secured Term Note (the “Note”) in the aggregate principal amount of $5 million. The Note has a three-year term and bears an interest rate equivalent to the “prime rate” published by the Wall Street Journal from time to time plus 3.25%, subject to a floor of 10% and a ceiling of 14% per annum. Concurrently with the agreements listed above, the Company amended and restated its previous $10 million Secured Term Note dated October 31, 2005 with Laurus Funds. Interest rates ranged from 11% to 11.75% during fiscal 2006. At December 31, the rate was 11.5%

The master security agreement establishes substantially all of our assets as collateral for the convertible note as well as for this note.

We acquired a truck on September 10, 2003 and financed the purchase with a five-year loan from GMAC bearing an interest rate of 8.74%.

We financed a vehicle with Cornerstone bank in 2005 with a four-year loan at an interest rate of 7.00%.

The aggregate principal payments of long-term debt are approximately 2007-$14,193,588, 2008-$10,106,337, and 2009-$3,063,558.

During the years ended December 31, 2006, 2005 and 2004, we have incurred loan fees in connection with our financing activities as follows:

Additionally, we have granted warrants for the secured notes to purchase up to 1,600,000 of our common stock at exercises prices ranging from $1.65 to $2.00 per share.

In 2006, 2005 and 2004 we accreted $1,295,726, $989,789 and $170,054, respectively to interest expense based on the value of the warrants when they were issued using the interest method.

We capitalize interest cost incurred on funds used in the development of our oil and gas properties. Capitalized interest is recorded as part of our capitalized oil and gas properties and is depleted over the estimated useful life of the assets. Interest cost capitalized for the years ended December 31, 2006 and 2005 was $808,714 and $0, respectively.

Deferred income taxes are determined based on the tax effect of items subject to differences in book and taxable income. We had no income tax provision for the years ended December 31, 2006, 2005 and 2004. There are approximately $22,500,000 of net operating loss carry-forwards, which expire in 2018-2021. The net deferred tax is as follows:

A reconciliation of the provision for income taxes to the statutory federal rate for continuing operations is as follows:

During the year ended December 31, 2004, we paid the outstanding balance due to an officer in the amount of $47,500.

Total interest paid to CDI , a shareholder of the Company, for the year ended December 31, 2004 was $15,778.

Total fees paid to Mr. David Polay and his company for the year ended December 31, 2005 and 2004 were $117,450 and $13,342, respectively.

We acquired oil and gas leases and existing wells on properties from BTB Energy for $270,000. This was included as an accrued liability at December 31, 2004. We also paid $150,000 to two of our shareholders for an operating property.

On June 30, 2006, we expensed a subscription receivable in the amount of $75,000 for one of our shareholders in exchange for public relation services rendered.

During the year ended December 31, 2006, we expensed compensation totalling $753,009 for our President and CEO. Pursuant to his employment agreement, $235,625 was paid as base salary and an additional $36,000 was included as compensation for non-accountable reimbursed expenses. On June 20, 2006, the board of directors authorized the issuance of a $100,000 cash bonus for services performed in connection with the new credit facility with Laurus Master Fund. The remaining balance of $381,384 represents the current year amortization of the executive options previously granted and extended.

During the year ended December 31, 2006, we paid fees to Caldwell & Moll, L.C. totalling $71,403 for legal services provided to us and $24,792 in expenses. Loren Moll, our Chairman, is a partner with the firm. As of December 31, 2006, the balance owed to Caldwell & Moll was $20,384. Additionally, Director fees and expenses payable to Mr. Moll totalling $6,242 were incurred at December 31, 2006, $2,000 were unpaid.

During the year ended December 31, 2006, we paid fees to Accuity Financial Services, Inc. (formerly Opus Pointe) totalling $82,500 for accounting services provided to us. Ms. Herring is a Director of the Company and is also an officer of Accuity Financial Services, Inc. As of December 31, 2006, the balance owed to Accuity Financial Services, Inc. was $18,000. Additionally, Director fees and expenses payable to Ms. Herring totalling $60,000 were incurred as of December 31, 2006, $5,000 were unpaid.

On January 15, 2004, we agreed to issue 765,000 shares of stock to Mr. John Haas, Mr. Mark Haas and Mr. W.B. Mitchell, principals of CBM Energy, Inc. in exchange for oil and gas mineral leases covering approximately 36,000 acres and title to approximately 10 existing wells. The value of the transaction is $765,000. $31,000 of value was assigned to properties not subject to amortization based on the unamortized lease cost of each leased acre. $80,000 of value was assigned to properties subject to amortization costs based on the fair market value of the test wells on the leased property. The remaining $654,000 was expensed.

Effective November 4, 2004, we completed the acquisition of certain assets owned by Savage Resources, LLC and Savage Pipeline, LLC for the purchase price of $10 million. The acquisition included leasehold rights to approximately 10,000 acres and 71 producing gas wells in Southeast Kansas.

In accordance with the terms of the purchase agreement, the purchase price was allocated as follows:

We utilize energy swaps to reduce exposure to un-favorable changes in natural gas prices through fixed-price contracts. These contracts allow us to predict with greater certainty the effective natural gas prices received for hedged production. These contracts also benefit operating cash flows and earnings when market prices are less than the fixed prices provided under the contracts. However, we will not benefit from market prices that are higher than fixed prices in contracts for hedged production. If we are unable to provide the quantity that we have contracted for we will have to go to the open market to purchase the required amounts that we have contracted to provide. For the year ended December 31, 2006 and 2005 fixed price contracts hedged approximately 84% and 80%, respectively, of our oil & gas production.

The following table summarizes our fixed price contracts as of December 31, 2006:

All fixed price contracts have been executed in connection with our natural gas hedging program. The differential between the fixed price and the floating price for each contract settlement period multiplied by the associated contract volume is the contract profit or loss. All of our contracts are considered to be cash flow hedges and there were no realized gains or losses in the years ending December 31, 2006 and 2005. The change in the fair value is shown as an adjustment to other comprehensive income with a corresponding balance sheet asset or liability recorded.

The counter parties to our fixed-price contracts are the customers buying our product. Should the counter party default on a contract there can be no assurance that we will be able to enter into a new contract with a third party on terms comparable to the original contract. We have not experienced non-performance. Cancellation or termination of a fixed-price contract would subject a greater portion of our gas and oil production to market prices, which in a low price environment, could have an adverse effect on our operating results.

Our asset retirement obligations relate to the abandonment of oil and gas wells. The amounts recognized were based on numerous estimates and assumptions, including future retirement costs, inflation rates and credit adjusted risk-free interest rates. The following shows the changes in asset retirement obligations for the financial statements presented.

The following information on our oil and gas development and producing activities is in accordance with SFAS No. 69, “Disclosures about Oil and Gas Producing Activities”.

Our aggregate capitalized costs related to natural gas and oil producing activities are as follows:

Unproved properties not subject to amortization consisted mainly of leases, and wells that haven’t been completed. We will continue to evaluate our unproved properties; however, the timing of ultimate evaluation and disposition of the properties has not been determined.

Capitalized costs incurred in natural gas and oil property acquisition, exploration and development activities are summarized as follows:

Our estimated net proved oil and gas reserves and the present value of estimated cash flows from those reserves are summarized below. The reserves were estimated by McCune Engineering, an independent petroleum engineer, using market prices at the end of each of the years presented in the financial statements. Those prices were held constant over the estimated life of the reserves. There are numerous uncertainties inherent in estimating quantities and values of proved oil and gas reserves and in projecting future rates of production and the timing of development expenditures, including factors involving reservoir engineering, pricing and both operating and regulatory constraints. All reserves estimates are to some degree speculative, and various classifications of reserves only constitute attempts to define the degree of speculation involved. Accordingly, oil and gas reserve information represents estimates only and should not be construed as being exact.

Our ownership interests in estimated quantities of proved oil and gas reserves and changes in net proved reserves, all of which are located in the United States, are summarized below.

The standardized measure of discounted future net cash flows from our proved reserves for each of the years presented in the financial statements is summarized below. The standardized measure of future cash flows as of December 31, 2006, 2005 and 2004 is calculated using a price per Mcf of natural gas of $7.50, $8.64 and $6.20, respectively and a price per barrel of oil at $54.00, $54.15 and $49.55 respectively. The gas price was the Southern Star spot gas price (inside FERC index) at the end of the year. The oil price was what we were receiving at each year end. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the estimated proved reserves. These costs are based on year-end cost levels. Future income taxes are based on year-end statutory rates.

The future net cash flows are reduced to present value by applying a 10% discount rate. The standardized measure of discounted future cash flows is not intended to represent the replacement cost or fair market value of the Company’s oil and gas properties.

The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of the Company’s proved oil and gas reserves after income taxes for each of the years presented in the financial statements. There are no revisions of quantity estimates. There were no extensions, discoveries and improved recoveries for the year ended December 31, 2004.

Summarized unaudited quarterly financial data for 2006, 2005 and 2004 are as follows:


	Quarters Ended
	December 31,			September 30,			June 30,			March 31,
	2006			2006			2006			2006

Total revenues	$	1,544,137		$	1,947,729		$	1,824,907		$	1,216,025
Operating (loss)		(2,155,136)	)		(422,825)	)		(996,632	)		(1,144,876	)
Net (loss)		(2,368,989)	)		(1,495,603)	)		(2,095,420	)		(1,835,196	)
Net (loss) per common share:
Basic and fully diluted	$	(0.08	)	$	(0.05	)	$	(0.07	)	$	(0.07	)

	Quarters Ended
	December 31,			September 30,			June 30,			March 31,
	2005			2005			2005			2005

Total revenues	$	754,934,		$	1,493,770		$	1,805,491		$	1,190,611
Operating (loss)		(1,871,566)	)		(811,768)	)		(183,087	)		(1,289,542	)
Net (loss)		(2,444,050)	)		(1,217,594)	)		(630,448	)		(1,671,704	)
Net (loss) per common share:
Basic and fully diluted	$	(.04)	)	$	(0.05	)	$	(0.03	)	$	(.06)	)

	Quarters Ended
	December 31,			September 30,			June 30,			March 31,
	2004			2004			2004			2004

Total revenues(1)	$	822,739		$	44,185		$	--		$	--
Operating (loss)		(660,072	)		(410,016	)		(681,569	)		(1,376,298	)
Net (loss)(4)		(2,073,679	)		(413,314	)		(679,589	)		(1,357,325	)
Net (loss) per common share:
Basic and fully diluted	$	(0.07	)	$	(0.02	)	$	(0.04)		$	(0.09	)

Nevada		90-0066187
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

PART I	Page

Item 1.	Business	5
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	31
Item 2.	Properties	31
Item 3.	Legal Proceedings	34
Item 4.	Submission of Matters to a Vote of Security Holders	34

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
Item 6.	Selected Financial Data	39
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	39
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	56
Item 8.	Financial Statements and Supplementary Data	57
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.	57
Item 9A.	Controls and Procedures	57
Item 9B.	Other Information	57

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	58
Item 11.	Executive Compensation	63
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	68
Item 13.	Certain Relationships and Related Transactions, and Director Independence	70
Item 14.	Principal Accountant Fees and Services	71

PART IV

Item 15.	Exhibits, Financial Statement Schedules	72

Term	Definition

Adsorb	A process by which molecules are taken up on the surface of a solid by physical or chemical action. Large amounts of gases may be adsorbed on the surface of a porous material such as coal.

Barrel	In the energy industry, a barrel is a unit of volume measurement used for petroleum and is equivalent to 42 U.S. gallons measured at 60 ° Fahrenheit.

Basin	A depressed area where sediments have accumulated during geologic time and considered to be prospective for oil and gas deposits.

Blowout	An uncontrolled flow of oil, gas, water or mud from a wellbore caused when drilling activity penetrates a rock layer with natural pressures greater than the drilling mud in the borehole.

Coal rank	The classification of coal relative to other coals, according to their degree of metamorphism, or progressive alteration, in the natural series from lignite to anthracite. Synonymous with coal quality.

Coalification process	A progressive process (bacterial decay and heat) that turns decayed plant material (peat) into the various ranks of coal. The first stage (peat to lignite) is decay and the remaining stages are thermal. The major by-products are methane, carbon dioxide, and water.

Completion / Completing	A well made ready to produce oil or natural gas. Completion involves cleaning out the well, running and cementing steel casing in the hole, adding permanent surface control equipment, and perforating the casing so oil or gas can flow into the well and be brought to the surface.

Desorb	The release of materials (e.g., gas molecules) from being adsorbed onto a surface. The opposite of adsorb.

Development	The phase in which a proven oil or gas field is brought into production by drilling production (development) wells.

Division order	A contract for the sale of oil or gas, by the holder of a revenue interest in a well or property, to the purchaser (often a pipeline transmission company).

Drilling	The using of a rig and crew for the drilling, suspension, production testing, capping, plugging and abandoning, deepening, plugging back, sidetracking, redrilling or reconditioning of a well. Contrast to “Completion” definition.

Drilling logs	Recorded observations made of rock chips cut from the formation by the drill bit, and brought to the surface with the mud, as well as rate of penetration of the drill bit through rock formations. Used by geologists to obtain formation data.

Exploration	The phase of operations which covers the search for oil or gas by carrying out detailed geological and geophysical surveys followed up where appropriate by exploratory drilling. Compare to “Development” phase.

Farm out	Assignment or partial assignment of an oil and gas lease from one lessee to another lessee

Gathering line / system	A pipeline that transports oil or gas from a central point of production to a transmission line or mainline.

Gross acre	An acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned

Gross well	A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.

Held-By-Production (HBP)	Refers to an oil and gas property under lease, in which the lease continues to be in force, because of production from the property.

Land services	Services performed by an oil and gas company or agent, or landman, who negotiates oil and gas leases with mineral owners, cures title defects, and negotiates with other companies on agreements concerning the lease.

Logging (electric logging)	Process of lowering sensors into a wellbore to acquire downhole recordings that indicate a well’s rock formation characteristics and indications of hydrocarbons

Methane	An organic chemical compound of hydrogen and carbon (i.e., hydrocarbon), with the simplest molecular structure (CH4)

Mineral Lease	A legal instrument executed by a mineral owner granting exclusive right to another to explore, drill, and produce oil and gas from a piece of land

Natural gas quality	The value of natural gas is calculated by its BTU content. A cubic foot of natural gas on the average gives off 1000 BTU, but the range of values is between 500 and 1500 BTU. Energy content of natural gas is variable and depends on its accumulations which are influenced by the amount and types of energy gases they contain: the more non-combustible gases in a natural gas, the lower the Btu value.

Net acre	A net acre is deemed to exist when the sum of fractional working interests owned in gross acres equals one. The number of net acres is the sum of fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Net well	A net well is deemed to exist when the sum of fractional working interests owned in gross wells equals one. The number of net wells is the sum of fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

Operator	A person, acting for himself or as an agent for others and designated to the state authorities as the one who has the primary responsibility for complying with its rules and regulations in any and all acts subject to the jurisdiction of the state

Pennsylvanian age	Geologic age of sediments deposited 320 to 286 million years ago

Permeability	The property of a rock formation which quantifies the flow of a fluid through the pore spaces and into the wellbore.
Pooled, Pooled Unit	A term frequently used interchangeably with “Unitization” but more properly used to denominate the bringing together of small tracts sufficient for the granting of a well permit under applicable spacing rules.

Proved Reserves	Estimated quantities of crude oil, natural gas, condensate, or other hydrocarbons that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in the future from known reservoirs under existing conditions using established operating procedures and under current governmental regulations.

Re-completion	Completion of an existing well for production from one formation or reservoir to another formation or reservoir that exists behind casing of the same well.

Reserves	Generally the amount of oil or gas in a particular reservoir that is available for production.

Reservoir	The underground rock formation where oil and gas has accumulated. It consists of a porous rock to hold the oil or gas, and a cap rock that prevents its escape

Reservoir Pressure	The pressure at the face of the producing formation when the well is shut-in. It equals the shut in pressure at the wellhead plus the weight of the column of oil in the hole.

Shut-in well	A well which is capable of producing but is not presently producing. Reasons for a well being shut-in may be lack of equipment, market or other.

Stratigraphic Trap	A variety of sealed geologic containers capable of retaining hydrocarbons, formed by changes in rock type or pinch-outs, unconformities, or sedimentary features.

Structural Trap	A variety of sealed geologic structures capable of retaining hydrocarbons, such as a faults or a folds.

Tight gas sandstones	Low permeability (having lower capacity to flow fluids through pore spaces) sedimentary rocks with natural gas occurring in the pore spaces. Contrast to high permeability sandstone definition.

Undeveloped acreage	Leased acreage which has yet to be drilled on to test the potential for hydrocarbons.

Unitize, Unitization	Joint operations to maximize produced hydrocarbon recovery among separate operators within a common reservoir

Western Interior Basin	Ancient inland sea and area of sediment deposition which divided North America into two separate landmasses in the Late Cretaceous Period, approximately 75 to 80 million years ago.

Working Interest	The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

	•	geological conditions;
	•	changes in governmental regulations and taxation;
	•	assumptions governing future prices;
	•	the amount and timing of actual production;
	•	availability of funds;
	•	future operating and development costs; and
	•	capital costs of drilling new wells.

	Proved
	Developed			Total
	Producing	Non-Producing	Undeveloped	Proved
Net Remaining Reserves
Oil (stock-tank barrels)	154,725	74,665	0	229,390
Gas (mcf)	3,966,538	4,558,465	4,308,900	12,833,903

Income Data
Future Net Cash Flows				$46,592,000
Discounted FNCF @10%				$30,872,000

	Years Ended December 31,
	2006	2005	2004
Production revenues	$6,532,798	$ 5,244,806	$ 866,924
Production and pipeline costs	(3,819,432)	(3,315,438)	(221,339)
Depreciation and depletion	(1,793,788)	(808,138)	(134,568)
Income tax (allocated on gross profits based on statutory rates)	(285,000)	(345,000)	(145,000)
Results of operations for producing activities	$ 634,578	$ 776,230	$ 366,017

	2006		2005
	High	Low	High	Low
1^st Quarter	2.19	1.55	2.65	2.25
2^nd Quarter	1.89	1.20	2.49	1.55
3^rd Quarter	1.39	0.44	2.25	1.45
4^th Quarter	0.78	0.43	1.76	1.69

	Year Ended December 31, (Audited)
	2006	2005	2004	2003	2002	2001
Revenue
Oil and gas activities	$ 7,489,401	$ 6,040,957	$ 866,924	$ -	$ -	$ -
Royalties and overrides	956,603	796,151	-	-	-	-

Gross profit	6,532,798	5,244,806	866,924	-	-	-

Expenses:
Direct costs	2,908,693	3,084,494	221,339	-	-	-
Pipeline costs	910,739	230,944	-	-	-	-
General and administrative	1,649,028	1,616,334	607,617	343,941	63,737	349
Professional and consulting fees	1,957,177	2,577,970	1,906,036	1,374,754	639,508	-
Salaries and wages	262,436	264,049	225,745-	-	-	-
Salaries and wages – related party	753,009	234,636	166,667-	-	-	-
Depreciation, depletion and amortization	2,811,185	1,392,342	213,475	-	-	-
Acquisition costs	-	-	654,000	-	-	-
Total expenses	11,252,267	9,400,769	3,994,879	1,718,695	703,245	349

Net operating (loss)	(4,719,469)	(4,155,963)	(3,127,955)	(1,718,695)	(703,245)	(349)

Other income (expense):
Interest expense	(3,075,739)	(1,807,833)	(1,395,952)	(15,089)	-	-

Net (loss)	$ (7,795,208)	$ (5,963,796)	$ (4,523,907)	$ (1,733,784)	$ (703,245)	$ (349)

Weighted average number of common shares outstanding – basic and fully diluted	28,777,494	25,632,220	20,647,542	14,721,438	8,338,208	6,454,360

Net (loss) per share – basic and fully diluted	$ (0.27)	$ (0.23)	$ (0.22)	$ (0.12)	$ (0.08)	$ (0.00)

Balance Sheet Data:	As of December 31, (Audited)
Balance Sheet Data:	2006	2005	2004	2003	2002	2001

Total Assets	$ 36,487,244	$ 26,927,034	$ 17,832,354	$ 2,577,447	$ 444,792	$ -
Total Liabilities	29,221,792	18,448,458	7,803,727	373,810	134,969	-
Stockholders’ Equity	$ 7,265,453	$ 8,478,576	$ 10,028,627	$ 2,203,637	$ 309,823	$ -

	Total		2007		2008-2009		2010-2011		Thereafter

Laurus Convertible Note	$	3,432,360	$	3,432,360	$	--	$	--	$	--
Laurus Term Notes		23,893,449		10,748,640₍₁₎		13,144,809
Asset retirement obligations		907,797		--		--		--		907,797
Notes Payable		37,674		12,588		25,086		--		--
Derivatives		58,133		--		58,133		--		--
Total	$	28,329,413	$	14,193,588	$	13,228,028	$	--	$	907,797

	Year Ending December 31,
	2007	2008
Gas
Contract volume	460,500	91,500
Weighted-average price	$7.95	$7.32

Oil Contract volume	--	--
Weighted-average price	--	--

Fair value asset (liability)	$974,752	($58,133)

Name	Age	Title	Term	Independent	Committees
Paul T. Branagan	63	President, CEO, Director, Secretary/Treasurer	Since 2002	No	Nominating
Loren Moll	50	Chairman	Since 2002	No	None
Suzanne Herring	42	Director	Since 2005	No	None
Robert H. Kite	52	Director	Since December 2006	Yes	Nominating
Duane D. Fadness	58	Director	Since December 2006	Yes	None

DIRECTOR COMPENSATION
Name (a)	Fees Earned or Paid in Cash ($) (b)	Stock Awards ($) (c)	Option Awards ($) (d)	Non-Equity Incentive Plan Compensa- tion ($) (e)	Non-Qualified Deferred Compensa- tion Earnings ($) (f)	All Other Compensa -tion ($) (g)	Total ($) (j)
Loren Moll (1)	$6,000	-0-	-0-	-0-	-0-	$242	$6,242

Suzanne Herring (2)	$60,000	-0-	-0-	-0-	-0-	-0-	$60,000

Duane Fadness	-0-	-0-	-0-	-0-	-0-	-0-	-0-

Robert Kite	-0-	-0-	-0-	-0-	-0-	-0-	-0-

Name of Beneficial Owner (1)	Number of Shares	Percent of Outstanding Shares of Common Stock (2)
Paul Branagan, President	2,250,000 (3)	8%
Loren Moll, Director	3,100,000	11%
Suzanne Herring, Director	0	*
Duane Fadness, Director	0	*
Robert Kite, Director	7,142	*
Directors and Officers as a Group	5,350,000	19%

Name of Beneficial Owner (1)	Number of Shares	Percent of Class (2)
Spindrift Investors (Bermuda) L.P. (3) (5) (6)* Clarendon House, 2 Church Street Hamilton	1,817,300	6%
Spindrift Partners, L.P. (4) (6) (7)* 75 State Street Boston, MA 02109	1,502,900	5%
Wellington Management Company, LLP (6)(8)* 75 State St. Boston, MA 02109	4,601,100 (9)	16%
Beneficial Owners as a Group*	7,921,300	27%

Signature	Title	Date

/s/ Paul Branagan	President, Secretary/Treasurer,	April 17, 2007
Paul Branagan	CEO, Director,
	Principal Accounting Officer


/s/ Loren Moll	Chairman of the Board	April 17, 2007
Loren Moll


/s/ Suzanne Herring	Director	April 17, 2007
Suzanne M. Herring


/s/ Duane Fadness	Director	April 17, 2007
Duane D. Fadness

Report of Independent Registered Public Accounting Firm	F-1

Consolidated Balance Sheets, December 31, 2006 and 2005	F-2

Consolidated Statement of Operations for the Years Ended December 31, 2006, 2005 and 2004	F-3

Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2006, 2005 and 2004	F-4

Consolidated Statement of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004	F-6

Notes to Consolidated Financial Statements	F-8 – F-31

	Options	Weighted Average Price	Warrants	Weighted Average Price
Outstanding 1/1/04	2,050,000	$1.12	2,400,000	$ 0.75
Granted	350,000	1.68	16,011,666	1.68
Cancelled	--	--	--	--
Exercised	(700,000)	0.50	(650,000)	0.75
Outstanding12/31/04	1,700,000	$1.49	17,761,666	$1.49

Outstanding 1/1/05	1,700,000	$1.49	17,761,666	$1.49
Granted	1,135,000	1.92	2,000,000	2.33
Cancelled	(60,000)	2.23	--	--
Exercised	--	--	(1,270,000)	1.34
Outstanding12/31/05	2,775,000	$1.67	18,491,666	$1.83

Outstanding 1/1/06	2,775,000	$1.67	18,491,666	$1.83
Granted	135,000	1.76	600,000	1.70
Cancelled	(100,000)	0.75	(3,950,000)	1.47
Exercised	--	--	(205,000)	1.18
Outstanding12/31/06	2,810,000	$1.70	14,936,666	$1.93

	December 31,
	2006	2005
Convertible note	$ 3,432,360	$ 6,172,942
Secured term note	25,000,000	10,000,000
Note payable to GMAC	16,930	16,791
Note payable to bank	20,739	26,879
Total	28,470,029	16,216,612
Less unamortized cost of warrants	(1,106,546)	(1,740,494)
	27,363,483	14,476,118
Less current portion	(14,193,588)	(2,101,111)
Long-term debt	$ 13,169,895	$ 12,375,007

	Financing Fees

Balance, December 31, 2003:	$	-0-
2004 Laurus Note		804,000
Current amortization		(67,000)
Balance, December 31, 2004:	$	737,000

Balance, January 1, 2005	$	737,000
2005 Laurus Note		525,086
Current amortization		(445,757)
Balance, December 31, 2005	$	816,329

Balance, January 1, 2006	$	816,329
2006 Laurus Notes		563,634
Current amortization		(717,452)
Balance, December 31, 2006	$	662,511

	December 31,
Non-current deferred tax asset (liabilities):	2006	2005	2004
Net operating loss carry-forward	$7,650,000	$3,940,000	$2,146,000
Oil & gas properties Valuation allowance	(5,226,000) (2,424,000)	(1,217,000) (2,723,000)	(839,000) (1,307,000)
Total deferred tax, net	$ --	$ --	$ --

	Year ended December 31, 2006
	2006	2005	2004
Statutory tax rate	34.0%	34.0%	34.0%
Non-deductible expense	7.8	9.5	40.0
Oil & gas properties	(21.4)	(5.8)	(40.0)
Change in valuation allowance	(20.4)	(37.7)	(34.0)
Effective tax rate	0.0%	0.0%	0.0%

Proved producing properties	$ 8,410,000
Equipment and vehicles	90,000
Pipeline	1,500,000
Total	$ 10,000,000

	Year Ended December 31,
	2006	2005	2004
Acquisition of properties proved & unproved	$ 256,172	$ 140,114	$ 8,912,126
Development costs	9,987,368	1,521,979	1,911,023
Total	$10,243,540	$1,662,093	$10,823,149

	Gas –mcf	Oil –bbls
Proved reserves:
Balance December 31, 2003	---	---
Purchase of reserves-in-place	12,837,406	111,296
Production	(142,968)	(306)
Balance December 31, 2004	12,694,438	110,990

	Gas-mcf	Oil-bbls
Proved developed reserves at the end of the year:

Balance, December 31, 2004	5,799,463	110,990

Balance, December 31, 2005	7,585,183	123,055

Balance, December 31, 2006	8,525,003	229,390

Year ended December 31, 2004
Future production revenue	$ 84,195,000
Future production costs	(24,012,000)
Future development costs	(6,093,000)
Future cash flows before income taxes	54,090,000
Future income taxes	(17,613,000)
Future net cash flows	36,477,000
10% annual discount for estimating of future cash flows	(13,198,000)
Standardized measure of discounted net cash flows	$ 23,279,000

Year ended December 31, 2005
Future production revenue	137,410,000
Future production costs	(50,919,000)
Future development costs	(11,027,000)
Future cash flows before income taxes	75,464,000
Future income taxes	(25,996,000)
Future net cash flows	49,468,000
10% annual discount for estimating of future cash flows	(14,888,000)
Standardized measure of discounted net cash flows	$ 34,580,000

Year ended December 31, 2006
Future production revenue	$ 109,137,000
Future production costs	(50,029,000)
Future development costs	(4,586,000)
Future cash flows before income tax	54,522,000
Future income taxes	(7,930,000)
Future net cash flows	46,592,000
10% annual discount for estimating of future cash flows	(15,720,000))
Standardized measure of discounted net cash flows	$ 30,872,000

Balance January 1, 2004	$ ---
Sales, net of production costs	(645,585)
Acquisition of oil and gas in place	23,924,585
Balance December 31, 2004	$ 23,279,000

Balance January 1, 2005	$ 23,279,000
Sales, net of production costs	(919,000)
Net changes in pricing and production costs	1,267,000
Extensions and discoveries	19,016,000
Revisions	(652,000)
Development costs incurred that were previously estimated	3,225,000
Net change in estimated future development costs	(8,159,400)
Accretion of discount	44,000
Change in income taxes	(2,521,000)
Balance December 31, 2005	$ 34,580,000

Balance January 1,2006	$ 34,580,000
Sales, net of production costs	(8,237,000)
Net changes in pricing and production costs	(14,394,000)
Extensions and discoveries	4,601,000
Revisions	(10,344,000) )
Development costs incurred that were previously estimated	4,816,000
Net change in estimated future development costs	1,625,000
Accretion of discount	52,000
Change in income taxes	18,173,000
Balance December 31, 2006	$ 30,872,000

Name of Subsidiary	State of Incorporation

Neodesha Pipeline, Inc.	Nevada
Coal Creek Pipeline, Inc.	Nevada