PETRON ENERGY, INC CONFIDENTIAL BUSINESS PLAN 17950 PRESTON ROAD SUITE 960 DALLAS, TEXAS 75252

PH (877) 373-8766

FAX (972) 485-1324

PROPRIETARY STATEMENT The material presented herein is the property of Petron Energy, Inc. and should not be reproduced or shared in any manner without the expressed written consent of Petron. ii

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Table of Contents

Pages 1 Table of Contents 2 Table of Exhibits 3 Mission/Vision Statement 4 Company at a Glance 5 The Opportunity Ahead 6 Introduction to the Cotton Valley Sandstone Trend 7 New Hybrid Frac Optimize Development in Sand Formations 8 Long-life, Multi-zone Production 9 Known Producing Field/Severance Tax Reduction/Horizontal

Drilling: New Developments in East Texas 10-11 New Terminology/History & Current Technology 12 Geological Summary-Cotton Valley Sandstone

Trend/Introduction 13 Technological Advancements/Opportunities/Stratigraphy 14 Stratigraphy-Rodessa/Pettit/Travis Peak/Cotton Valley 15 Industry at a Glance-National Energy Policy/Taking Stock

Energy Challenges Facing the United States/Natural Gas 16 U.S. Natural Gas Markets 17 Natural Gas Demand-Projected Natural Gas Use for Electricity

Generation Peaks in 2020 18 Natural Gas Consumption Varies with Fuel Prices and

Economic Growth/ Natural Gas Supply-Net Exports of Natural Gas Grow in the Projections/Energy Trends to 2030

19 Unconventional Production is a Growing Source of U.S. Gas Supply/Natural Gas Supply Projections Reflect Rates of Technology Progress

20 Natural Gas Prices Remain Above Historical Levels/Product 21 Marketing Strategy 22 Customers/Financial Forecast 23-24 Operational Plan/Management and Organization 25-26 Economic and Future Outlook 27 Capitalization/Use of Proceeds 28 3 Year Cash Flow Projections 32 Earnings Per Share Worksheet 33 Assumptions & 5 Year Operating Projections

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Exhibits

Page Exhibit Description 39 A New Hybrid Frac Sheet 40 B Tax Benefits Sheet 41 C C.V. Horizontal/Vertical vs. Horizontal 42 D Packer Plus IP Comparison 43 E Stratigraphic Column 44 F U.S. Energy Prices Chart 45 G Energy Consumption Chart 46 H Total Energy Supply Chart 47 I C. V. Wells Success Rate & IP

Comparison 48 J 20 Year Production History Chart 49 K 12 Month Production History Chart 50 L Natural Gas Demand Chart 51 M Schematic Diagram 52 N Well Location Map 53 O Pipeline Infrastructure 54 P Gas Well Prod. Charts A & B 55 Q Start of World Energy 56 R Mineral Lease Contract

PETRON ENERGY, INC. BUSINESS PLAN

Mission Petron Energy’s mission creates a solid foundation for the company. Our core beliefs upon which we founded the company are represented and the basic essentials are in position for our continued success. Mission Statement Petron Energy is a performance based oil and gas company. We are committed to an old fashion way of doing business which involves integrity, diligence, honesty, trustworthiness and responsibility when developing investor relationships and associate relationships. Vision Statement Petron Energy is very committed to establishing long-term relationships with its investment partners based on our solid performance. The marketing niche for Petron is apparent. Our company unites with our partners to identify and capitalize on low risk drilling opportunities by working in areas with years of proven production history. Petron is committed to integrity, diligence, honesty, trustworthiness, and responsibility when developing partner relationships. We feel our industry offers investors an opportunity to participate in an investment vehicle, which provides conservative, long-term monthly income potential and favorable tax benefits. The Cotton Valley Trend has proven to be an area which provides conservative long-term asset appreciation and our experiences validate the success of this area. Petron Energy’s goal is to further develop the Cotton Valley Trend and other energy properties which are congruent with our strategy.

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Company At A Glance Petron Energy, Inc. is a 9 year old oil and gas exploration and development company. We have invested primarily in mineral properties in Texas and Louisiana since the company’s inception. Petron Energy has been a Texas corporation since 1998, Mr. Floyd Smith founder, has been the sole owner since its inception. During the companies years of operations it has weathered challenges, such as under performing well and re-entry failures. We have been very diligent in researching more productive locations which provide a long-term proven history of success and display characteristics of being an under developed asset. By applying new technologies we are able to exploit and produce more natural gas and oil from these assets. Mr. Floyd Smith has been involved in the industry for 15 years. He is a very detailed oriented driven owner who knows how to set goals and initiate execution through completion. Our target market is the East Texas Cotton Valley Trend, which offers an extremely high success rate with respect to developing producing wells and it offers long term cash flow. Typical production from Cotton Valley wells usually have a life expectancy of 10 - 25 years. The Cotton Valley Trend is primarily a Natural Gas trend; however some wells make oil production along with gas production. Demand for natural gas is growing at a rate of 3% per year, while supply is only growing at a rate of 1% per year. Natural Gas is a clean burning alternative fuel and is environmentally friendly. Petron will be known as a natural gas company because of the long term implications of this environmentally friendly alternative fuel. We have a unique opportunity to capitalize on the newest form of innovative technology in the Cotton Valley Trend which involves a new process in fracture stimulation techniques. This process allows a far more efficient stimulation effect over a greater production area and the results have the potential of improving production rates by 5 - 10 times in horizontal wells versus the rate of vertical wells. We found such an opportunity in the Cotton Valley. Petron has invested in the development of 26 wells in the Cotton Valley Trend during the past 30 months. We developed a process that is successful in the Trend. Our wells are producing at a higher sustained rate with conservative declines.

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One of the challenges of the company will be securing the mineral lease prior to becoming a public company (see Exhibit R). Our plan is to use $1,500,000.00 of the investment capital for lease acquisitions. The mineral leases provide the company with a firm position for future development and improves shareholder value. In considering a more short term approach to improved share value and company cash flow, we plan to trade shares in the company for interest owned by investors in 3 of our earlier multiple well projects. We will utilize our current industry relationships to acquire a 10 -25 % industry level participation in 4 - 5 multiple well projects. Our long-term plan is to grow the company at a rate of 5% per year thru three approaches 1) lease acquisition and development, 2) industry level participation through current industry partners, 3) acquisitions of small operators in the Cotton Valley Trend and other areas which are congruent with our methodology. Items 1 & 2 of the long-term plan should be initiated within 12- 18 months of our successful investment capital campaign. The Opportunity Ahead Petron Energy is focusing on natural gas development in the U.S. because the U.S. offers a very mature basin for oil and a virgin market with upside for natural gas opportunities. U.S. offshore oil exploration or international oil plays face political, environmental, operational and financial risk whereas, the U.S. Natural Gas development offers:

• Low risk opportunities • Growth opportunities • Unlimited upside profit potential with unconventional gas reserves • Completion technological improvements which increase gas

reserves Benefits of Natural Gas over other energy sources:

• Natural Gas is potentially a key solution to global warming • Clean burning Natural Gas meets critical environmental concerns • Natural Gas is the fuel of choice for industry, residential and

electricity

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The Cotton Valley Trend encompasses a nine county area. In this nine county area there is a vast amount of available lease acreage to develop oil and gas production. During the last twenty years, the Cotton Valley Trend has experienced a 98 % success rate in wells finding commercial production in the Cotton Valley reservoir. During the last twenty four months we have been active in developing 26 consecutive natural gas wells. All of these wells are vertical producers. Each well was fracture stimulated for optimal production. The initial production rate on these wells are 750 thousand cubic feet of gas per day (mcfg/d) to 1850 million cubic feet of gas per day (mmcfg/d), each well has additional behind pipe reserves which extends the wells long term production and these reserves will be produced later in the wells production life. On vertical wells, the fracture stimulation process effects a production radius of 250 - 500 feet. around the vertical wellbore. (see Exhibits A, M, N) Introduction To The Cotton Valley Sandstone Trend East Texas has long been an extremely active area of drilling, discovery and production for over 70 years. In the counties which include Panola, Rusk, Harrison, Gregg, Smith, Shelby, Wood & Upshur in Texas, and Caddo, Red River, and Desoto Parishes in Louisiana, there is an extensive blanket sand group commonly referred to as the Cotton Valley Trend. It reaches from northeast Texas, through northwest Louisiana, and north to southwest Arkansas. The existence of this field has been known since mid-1930, but focused development did not truly begin until mid-1970 catalyzed by improvements in hydraulic fracturing technology and higher gas prices. Spacing guidelines have also changed over the years. Originally the guidelines were one well per 640 acres. Drilling is currently occurring on 40 acre spacing due to improved reservoir engineering indicating an effective drainage area of only 40 acres per well. Drilling and developmental activity is nearing an all time high. Areas of development were previously limited historically to wells that could achieve production equal to or greater than 2 billion cubic feet of gas (bcfg) per well. Higher prices, lower cost stimulation techniques, coupled with the fact that there is virtually no exploration risk for this extensive blanket-like formation. Also, the very reasonable opportunity to also encounter the Pettit formation between 6,500’-7,000’ and the Travis Peak

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formation between 7,500’ – 8,500’ in some 20% of wells drilled, makes the Cotton Valley Trend a low risk opportunity. Transporting natural gas to market is accomplished by using a well developed transportation pipeline infrastructure which has been in place for over 30 years. (see Exhibit O) New Hybrid Fracs Optimize Development In Sand Formations When sandstone rocks contain oil or gas in commercial quantities, recovery can be vastly improved by a process called fracturing which is used to increase permeability to its optimum level. Basically, to fracture a formation, a fracturing service company pumps a specifically blended fluid down the well and into the formation under great pressure. Pumping continues until the formation literally cracks open. Meanwhile, a special type of frac sand is mixed into the fracturing fluid. These materials are called proppants. The proppant enters the fractures in the formation and when pumping is stopped and the pressure allowed to dissipate, the proppant remains in the fractures. Since the fractures try to close back together after the pressure on the well is released, the proppant is needed to hold or prop the fractures open. These propped-open fractures provide passages for oil or gas to flow into the well. A series of studies and experimentation in the design of frac treatments have improved development and stimulation practices in the Sandstone formations of East Texas. Advanced hydraulic fracture diagnostics and documented production results over the first six months of well life have been used to better understand fracture geometry and well performance. The objective of the diagnostics is to improve fracture length and optimize fracture treatment design. The resulting changes to completion and stimulation design have resulted in improved well performance. The East Texas Basin has a series of productive formations which include the Rodessa (limestone), the Pettit (limestone), the Travis Peak (sandstone and shale), and the Cotton Valley (sandstone and shale). The primary target of drilling is generally to the Cotton Valley Sands at 9,000’ to 11,000’ in depth. The adoption of “slick” water and hybrid fracture treatments, sand proppants, plus multi-staging the treatments in the Lower, Middle and Upper Cotton Valley, when utilized in certain wells, may increase initial production rates, decrease decline rates and improve total reserve recoverability. This

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has to be determined area by area, and well by well, and may not be appropriate in all cases. In addition to new technology, a myriad of other variables can be applied to produce better results. We are constantly tracking different well completion strategies and production results to generate an approach that will yield the following: • Higher initial flow rates • Slower decline rates • Improved recoverability We are convinced that all three of the above goals can be achieved. Texas oil and gas industry records as of June 2004 in the eight Texas counties which are listed above, indicated some 80 companies, including Anadarko, BP America, Chevron, Devon Energy, Exxon Mobil, EOG, El Paso Natural, Texaco, Union Oil of CA and others, have been issued approximately 551 drilling permits. In the last year between April 2004 to April 2005, there were 1,508 permits issued in the six primary Texas Counties of Gregg, Harrison, Panola, Rusk, Smith and Upshur, giving rise to higher costs and creating intense rig demand. We have established a four star criteria for a Cotton Valley Trend drilling location. • Onstrike and close proximity to other excellent producers • Geographic access to inter-state markets • Multi-zone potential • Favorable lease terms (high net revenue leases) Long-life, Multi-zone Production Typical Cotton Valley Sandstone wells continue to produce in economic quantities from a low of 10 years, but commonly up to 25 years. Also, the Travis Peak and Pettit Formations can add significant reserves to any Cotton Valley well. However, unlike Cotton Valley Sandstone Formation, these “behind pipe” reservoirs will not produce in every well. (see Exhibit P)

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Known Producing Field The proposed drilling area is part of a well known trend that extends over a large area in the corners of northeast Texas, northwest Louisiana, and southwest Arkansas. The fields have been known and active since mid-1930, with earnest development occurring subsequent to mid-1970. With the advent of spacing changes and improved technology, recent drilling in this area is approaching an all time high. Severance Tax Reduction Cotton Valley production is subject to a significantly reduced Severance Tax from the normal 7.5% to 2.1% for the first 120 months (10 years), and then graduates up over an extended period of time. This reduction was enacted to stimulate drilling in the Cotton Valley Trend. Typical Cotton Valley wells continue to produce in economic quantities from 10 years, up to potentially 25 years. Decline rates are modest as viewed over an extended period of time. (see Exhibit B) Horizontal development is now being implemented in the Trend; this procedure has been around for decades. However, what is new about this drilling technique is the completion process. In years past horizontal wells were completed like their sibling vertical wells, which lead to poor efficiency in the completion process and well production rates. (see Exhibit C) Horizontal Drilling: New Developments In East Texas Devon Energy has recently permitted, drilled and completed a horizontal well in Panola County, in the Cotton Valley, with a 5 Stage fracture stimulation the well produced at 6.635 million cubic feet of gas per day (mmcfg/d) plus 105 barrels of oil per day (bo/d) on a 12/64 choke. They have 5 more wells scheduled for horizontal drilling in that area. We have been following and analyzing the introduction of horizontal drilling in the Cotton Valley Trend. The major service companies associated with our Cotton Valley operation also handled the job for Devon. It was clear that the time had come to step-up and participate in this increased production opportunity for our wells.

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The key participants in the technological effort include Halliburton, Schlumberger, as well Packer Plus Technology, including StackFrac™ and RapidMatrix™ Multi-Stage Fracturing and Stimulation Systems, which are designed specifically for isolated open hole fracturing of both sandstone and carbonate reservoirs. This innovative and field proven system greatly increases both the initial productivity, as well as the long-term recoverability from each wellbore when utilizing the high performance RockSeal™ II Packer. This system allows for precise placement of fracturing fluids for optimum stimulation results and maximized post-fracturing productivity of the well. When combined with newly designed advanced stimulation fluids, you produce multiple fractures of greater effective conductivity along the entire wellbore. This open hole fracturing and treating provides less reservoir contamination from cement, and allows for a wider, longer frac matrix. (see Exhibit D) New Terminology (TVD) Total Vertical Depth: Total depth reached as measured along a line drawn to the bottom of the hole that is also perpendicular to the earth’s surface. (MSD) Measured Depth: Measures total distance drilled along the well bore. (Note that in a vertical hole, (MSD) would equal (TD), Total Depth). (HD) Horizontal Displacement: Total distance drilled along the quasi-horizontal portion of the wellbore. History & Current Technology The first recorded true horizontal well, was drilled near Texon, Texas (just west of San Angelo), and was completed in 1929. Another was drilled in 1944 in the Franklin Heavy Oil Field, Vanago County, Pennsylvania, at a depth of 500 feet. China tried horizontal drilling as early as 1957, and later on the Soviet Union tried as well. Generally, however, little practical application occurred until the early 1980’s, by which time the advent of improved downhole drilling motors and the invention of other necessary supporting equipment, materials, and technologies, particularly downhole telemetry equipment, had brought some kinds of applications within the imaginable realm of commercial viability.

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A widely accepted definition of what qualifies as “horizontal drilling” had yet to be written, however the following combines the essential components of previously published definitions. Horizontal drilling is the process of drilling and completing, for production, a well that begins as a vertical or inclined linear bore which extends from the surface to a subsurface location just above the target reservoir, then bears off on an arc to intersect the reservoir at the “entry point”, and, thereafter, continues at a near-horizontal angle and will substantially or entirely remain within the reservoir until the desired bottom hole location is reached. According to an Energy Information Administration (EIA) review of horizontal well technology and its domestic applications, horizontal drilling technology achieved commercial viability during the late 1980’s. It has been successfully employed in a variety of fields and formations in many domestic geographic regions and geologic situations. Completion and production techniques have been modified for the horizontal environment, with more change required as the well radius decreases. The specific geologic environment and production history of the reservoir also determine the completions methods employed. The technical objective of horizontal drilling is to expose significantly more reservoir rock to the well bore surface than can be achieved via drilling of a conventional vertical well. The two primary benefits of horizontal drilling success are 1) increased productivity of the reservoir, as well as 2) prolongation of the reservoir’s commercial life. An offset to the benefits provided by successful horizontal drilling is its higher cost, but the average cost is going down. It is probable that the cost premium associated with horizontal drilling will continue to decline as horizontal drilling activity increases. But there is always the possibility that new and improved technology could add additional costs in the future. Horizontal wells have a higher productivity and pay zone contact per well than vertical wells, and allow operators to take advantage of highly heterogeneous or layered reservoirs, like the Cotton Valley Sandstone. Horizontal drilling is now utilized in a variety of carbonate and sandstone reservoirs across the country, including the Austin Chalk, James Lime, Woodbine and the Barnett Shale here in Texas.

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The new Packer Plus System has revolutionized the completion process with regard to horizontal wells (see exhibit D). It allows for the completion job in the horizontal leg of the hole to be customized. We are able to isolate individual 500 feet sections and plan 5 to 7 fracture stimulation treatments on a 2500 feet leg. This provides a greater level of effectiveness in the stimulation process and daily production levels reflect this technological improvement. This stimulation procedure provides a greater area of production, usually 10 times greater production area than a vertical wells radius. Rates have improved 5 to 10 times that of vertical wells. We feel our niche is clearly defined, we have identified the area and this process allows Petron an opportunity to exploit the Cotton Valley Trend and capitalize on the vast amounts of Natural Gas Reserves in place. Geological Summary Cotton Valley Sandstone Trend Introduction The Cotton Valley sand group contains many massive, low permeability, low porosity sands. These extend over a large area in the corners of northeast Texas, northwest Louisiana, and southwest Arkansas. Although this fields’ existence had been known since mid-1930, earnest development did not start until mid-1970 after improvements in hydraulic fracture technology and higher gas prices. The original spacing rules in the Cotton Valley Field were established at one well for each 640 acres, this spacing rule was changed in February 1981 to 320 acres per well. With the recent stability of higher gas prices, and the most recent spacing change to 40 acres per well, Cotton Valley drilling is approaching an all time high. The Cotton Valley sands were deposited during the late Jurassic Period. The depositional environment is interpreted as a regressive and transgressive sequence of shallow water, bioturbated, shoreface sediments dominated by barrier bars with minor interbeds of tidal deltaic deposits. Each of these shallow marine bars contain many layers of sand and shale. The sand layers were deposited during the storms and shale layers during fair weather periods. This is typical of a prograding barrier bar system.

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Technological Advancements The adoption of water fracs or hybrid fracs in the Cotton Valley sandstone has greatly reduced the fracture stimulation cost, while providing similar production results to the massive proppant procedures previously used in the field. The water fracs employ a polymer-free fracturing fluid composed of water, clay stabilizers, surfactants and friction reducer. The proppant concentrations are reduced to a maximum amount of 0.5 lbs/gal, which is kept constant throughout the proppant laden stage. At the end of the job (last 5%) proppant concentration is ramped up to a maximum of 5 lbs/gal as a safety measure to ensure that the near-wellbore region is propped. Traditional fracture treatments in this area used cross-linked-fracturing fluids with maximum proppant concentrations up to 8 lbs/gal. Opportunities The current interest in the Cotton Valley sandstone trend is clearly prompted by the long-term confidence of natural gas pricing. The trend development has historically limited itself to selected areas that could achieve greater than 2 BCF. However, with higher prices, lower cost stimulation techniques, coupled with the fact that there is virtually no exploration risk for the Cotton Valley, and a reasonable opportunity to also encounter a productive Travis Peak formation, makes the Cotton Valley Trend a low risk opportunity to build long-term gas reserves. Stratigraphy The producing reservoirs in the fields are of Lower Cretaceous Age Rodessa, Pettit, and Travis Peak, ranging in depth from 6,700 to 9,000 feet, and the Upper Jurassic Age Cotton Valley ranging in depth of 9,000 to 10,800 feet. The producing zones in descending order are the Upper Gloyd, Lower Gloyd, Upper Young, Lower Young, the Pettit “E”, Upper Travis Peak, Middle Travis Peak, Lower Travis Peak, Upper Cotton Valley and Lower Cotton Valley (Taylor).

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Rodessa The Rodessa section is 825 feet of limestone, sand and shale. Five individual limestone zones produce in the Trend. They are the Upper and Lower Gloyd Deep Sand and the Upper and Lower Young. The Upper Gloyd is a limestone interval in the upper part of the Rodessa section. The Upper Gloyd in one area of interest is 6 to 14 feet thick. Pettit The Pettit is a 330 foot interval of limestone and shale. There are two to five limestone intervals, in the Pettit reservoir. The lower limestone interval, the Pettit “E” is the most productive interval. Production comes from porosity development within the interval. Travis Peak The Travis Peak is a 1,730 foot interval of sand and shale. The Upper Travis Peak is a sandstone interval comprising the top third (~550 feet) of the Travis Peak. Production comes from multiple sands with an average pay thickness of 7 feet and 10% porosity and 37% water saturation in one area of interest. The Middle Travis Peak is a sandstone interval comprising the middle third (~550 feet) of the Travis Peak. Production comes from multiple sands with an average thickness of 8 feet and 10% porosity and 34% water saturation in several areas of interest. The Lower Travis Peak is a sandstone interval comprising the lower third (~550 feet) of the Travis Peak. Production comes from multiple sands with some areas showing an average pay thickness of 10 feet and 9% porosity and 31% water saturation. There are the potential of 10-15 individual pay zones available in the Travis Peak reservoir. Cotton Valley The Upper Cotton Valley is a 1,300 foot interval consisting of a series of sandstones and shales. The upper 1,000 feet of the interval is productive with scattered pay. The Lower Cotton Valley (Taylor) is a 300 foot sandstone and shale interval above the Bossier Shale. There is the potential of 15-30 individual pay zones available in the Cotton Valley reservoir. (see Exhibit E, M)

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Industry At A Glance National Energy Policy From the Report of the National Energy Policy Development Group May 2001, entitled “Taking Stock, Energy Challenges Facing the United States” Taking Stock Energy Challenges Facing the United States America’s current energy challenges can be met with rapidly improving technology, dedicated leadership, and a comprehensive approach to our energy needs. Our challenge is clear – we must use technology to reduce demand for energy, repair and maintain our energy infrastructure, and increase energy supply. Natural Gas Natural gas is the third largest source of U.S. electricity generation, accounting for 16% of generation in 2000. Under existing policy, natural gas generation capacity is expected to constitute about 90 percent of the projected increase in electricity generation between 1999 and 2020. Electricity generated by natural gas is expected to grow to 33 percent in 2020 – a growth driven by electricity restructuring and the economics of natural gas power plants. Lower capital costs, shorter construction lead times, higher efficiencies, and lower emissions give gas an advantage over coal and other fuels for new generation in most regions of the country. Overall, natural gas accounts for 24 percent of total U.S. energy consumed and for all purposes 27 percent of domestic energy produced. Eighty-five percent of total U.S. natural gas consumption is produced domestically. Between 2000 and 2020, U.S. natural gas demand is projected by the Energy Information Administration to increase by more than 50 percent, from 22.8 to 34.7 trillion cubic feet. More than half of the increase in overall gas consumption will result from rising demand for electricity generation. The projected rise in domestic natural gas production – from 19.3 trillion cubic feet in 2000 to 29.0 trillion cubic feet in 2020 – may not be high enough to meet projected demand. The most significant long-term challenge relating to natural gas is whether adequate supplies can be provided to meet sharply increased projected

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demand at reasonable prices. If supplies are not adequate, the high natural gas prices experienced over the past years could become a continuing problem. To meet this long-term challenge, the United States not only needs to boost production, but also must ensure that the natural gas pipeline network is expanded to the extent necessary. The U.S. Natural Gas market has enjoyed consistent growth for the last several years. Current demand for natural gas product to end users has grown at a rate of 3% per year, whereas supply has only grown at a rate of 1%. The winter of 2006 was colder later into the winter unlike winters past and it was reflected in our price point and in our inventory levels. Prices were low compared to the normal double digit increases we typically see with colder winter conditions. Inventory levels were drawn down in record amounts in February. As a result after 13 consecutive months of year-over-year increases, February stocks dropped below the year-ago level. Stocks are 263bcf below the level at the same time last year (AEO2007). Michael Zenker with Cambridge Energy Research Associates said “I would estimate prices would average about $7.00 mcf through 2008. The rising demand for gas, coupled with flat production, has tripled prices in the last four years”. The Energy Information Administration (EIA), the statistical branch of the Department of Energy has completed its comprehensive Annual Energy Outlook 2007 Report (AEO2007), with projections to 2030. This report presents a projection and analysis of U.S. energy supply, demand, and prices through 2030. The projections are based on results from the EIA’s national modeling system. U. S. Natural Gas Markets Prices. The Henry Hub natural gas price is projected to average $7.58 per thousand cubic feet (mcf) in 2007 compared with $6.94 in the previous Outlook (Henry Hub Natural Gas Price). For 2008, the Henry Hub spot price is projected to average $7.86 per mcf. ( see exhibit F) Production. Domestic dry natural gas production is expected to increase by 2.4 percent in 2007, a slight increase from production growth in 2006, as drilling for natural gas continues at historically high levels. Net imports of natural gas in 2007 are projected to drop for the second consecutive year, though a smaller decline is expected in 2007.

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Inventories. On February 23, 2007, working gas in storage stood at an estimated 1,733 billion cubic feet (bcf). Due to cold weather, a record amount of natural gas was withdrawn from storage in February. As a result, after 13 consecutive months of year-over-year increases, February stocks dropped below the year-ago level. Stocks are 263 bcf below the level at this time last year, but are still 179 bcf above the 5-year average (U.S. Working Natural Gas in Storage). Consumption. A return to normal temperatures in 2007 is expected to drive strong year-over-year growth in residential consumption of natural gas. A first quarter comparison of EIA’s estimated residential consumption shows a 14 percent increase from 2006-2007. Taking the year as a whole, residential consumption is expected to increase 10.8 percent in 2007. Similarly, commercial and industrial sector consumption are expected to increase by 6.3 and 1.9 percent, respectively, in 2007 because of a return to normal weather, lower commercial prices, and growing industrial output. Total natural gas consumption growth for 2007 and 2008 is projected to increase by 2.9 and 1.8 percent, respectively, after falling by 1.7 percent in 2006 (Total U.S. Natural Gas Consumption Growth.) Natural Gas Demand Projected Natural Gas Use for Electricity Generation Peaks in 2020 Total natural gas consumption in the United States is projected to increase from 22.0 trillion cubic feet in 2005 to 26.1 trillion cubic feet (tcf) in 2030 in the AEO2007 reference case (see exhibit G). Much of the growth is expected before 2020, with demand for natural gas in the electric power sector growing from 5.8 tcf in 2005 to a peak of 7.2 tcf in 2020. Continued growth in residential, commercial, and industrial consumption of natural gas is roughly offset by the projected decline in natural gas demand for electricity generation. As a result, overall natural gas consumption is almost flat between 2020 and 2030 in the AEO2007 reference case, and the natural gas share of total projected energy consumption drops from 23 percent in 2005 to 20 percent in 2030.

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Natural Gas Consumption Varies with Fuel Prices and Economic Growth In contrast, the price of natural gas directly affects the level of natural gas consumption. High prices provide a direct economic incentive for users to reduce their natural gas consumption, and low prices encourage more consumption. The strength of the relationship between natural gas prices and consumption depends on the short- and long-term capabilities for fuel conservation and substitution in each consuming sector. Natural Gas Supply Net Exports of Natural Gas Grow in the Projections Net exports of U.S. natural gas to Mexico are projected to decline from nearly 400 billion cubic feet (bcf) in 2007 to 35 billion in 2019. After 2019 they are expected to increase steadily to nearly 250 bcf in 2030. Energy Trends to 2030 Despite the rapid growth projected for biofuels and other nonhydroelectric renewable energy sources and the expectation that orders will be placed for new nuclear power plants for the first time in more than 25 years, oil, coal, and natural gas still are projected to provide roughly the same 86 percent share of the total U.S. primary energy supply in 2030 that they did in 2005. The energy price projections for natural gas and coal in the AEO2007 reference case also are similar to those in AEO2006. The real wellhead price of natural gas is projected to decline from current levels through 2015, when new supplies enter the market, but it does not return to the levels of the 1990s. After 2015, the natural gas price rises to $8.27 per thousand cubic feet in 2030. (see Exhibit H) Natural gas consumption is projected to grow to 26.1 trillion cubic feet (tcf) in 2030, down from the projection of 26.9 (tcf) in 2030. Total natural gas consumption is almost flat from 2020 through 2030, when growth in residential, commercial, and industrial consumption is offset by a decline in natural gas use for electricity generation as a result of greater coal use. The average U.S. natural gas in the AEO2007 reference case declines gradually from the current level, as increased drilling brings on new supplies

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and new import sources become available. The average price falls to just under $6.46 per thousand cubic feet in 2015 (2005 dollars), then rises gradually to about $8.27 per thousand cubic feet in 2030. (see Exhibit H) In the AEO2007 reference case, the natural gas share of electricity generation (including generation in the end-use sectors) is projected to increase from 19 percent in 2005 to 22 percent around 2016, before falling to 16 percent in 2030. Total domestic natural gas production, including supplemental natural gas supplies, increases from 18.3 trillion cubic feet in 2005 to 21.1 trillion cubic feet in 2022, before declining to 20.6 trillion cubic feet in 2030 in the AEO2007 reference case. In comparison, domestic natural gas production was projected to peak at 21.6 trillion cubic feet in 2019 in the AEO2006 reference case. Unconventional Production Is a Growing Source of U.S. Gas Supply A large proportion of the onshore lower 48 conventional natural gas resource base has been discovered. Discoveries of new conventional natural gas reservoirs are expected to be smaller and deeper, and thus more expensive and riskier to develop and produce. Accordingly, total lower 48 onshore conventional natural gas production declines in the AEO2007 reference case from 6.4 trillion cubic feet in 2005 to 4.9 trillion cubic feet in 2030. Incremental production of lower 48 onshore natural gas comes primarily from unconventional resources, including coalbed methane, tight sandstones, and gas shales. Lower 48 unconventional production increases in the reference case from 8.0 trillion cubic feet in 2005 to 10.2 trillion cubic feet in 2030, when it accounts for 50 percent of projected domestic U.S. natural gas production. Natural Gas Supply Projections Reflect Rates of Technology Progress Technological progress generally reduces the cost of natural gas production, leading to lower wellhead prices, more end-use consumption, and more production.

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Natural Gas Prices Remain Above Historical Levels In the AEO2007 report the natural gas prices are projected to decline from current levels to an average of $6.91 per thousand cubic feet in 2010, then rise to $8.27 per thousand cubic feet in 2030. (see exhibit D) Current high natural gas prices are expected to stimulate the construction of new LNG terminal capacity, resulting in a significant increase in LNG import capacity. Projected natural gas prices are expected to stimulate the construction of an Alaska natural gas pipeline (projected to begin in operation in 2018), as well as increased unconventional natural gas production. This is a plus for us because the Cotton Valley Trend has 25% NGL’s (natural gas liquids) which represents additional revenue from the sell of those liquids. Product The petroleum industry has long been an integral thread in the fabric of the world. It offers certain features and benefits to those of us who actively invest. Some are listed below. Features

• Long term monthly income • Per share value appreciation • Tax incentives • Depletion allowance • Publicly traded companies offer a secondary market for exit • Multiple pay zone production • Proven historical development success • Severance tax savings

Benefits

• Monthly disposable income • Estate and Net worth appreciation • Reduction in taxes • Tax free income • Flexible exit strategy through secondary market • Reduces risk of low commercial production

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• Reduction of dry hole risk • Increased monthly cash flow

Marketing Strategy Experts look through futuristic lens and the energy industry looks bright for a healthy pricing environment. Global demand is high, yet global production is on the decline. We have spent the last few years strategizing how to effectively capitalize on these unique times in our industry, and we believe the time is right to generate a core asset base through low risk natural gas reserves. Our three-point approach would involve: (1) The creation of a leasebank which would allow for acquisition of leases in proven developmental areas. Our lease position in low risk development areas provides us the ability to diversify into multiple wells further reducing our risk, and more accurately predicting return on investment. In summary, Petron Energy will be uniquely positioned to generate, develop and manage low-risk projects with proven predictability. Through the development of theses leases, we would be able to add value to the company from monthly production of each well and the book value of the behind pipe reserves of each well and pud’s (proved underdeveloped reserves) of the lease. (2) The second approach would involve the continued participation with current industry relationships. The company can achieve prime production acreage and interest by partnering with pre-existing industry relationships that we are familiar with and in areas we’re comfortably positioned. It provides our company with an opportunity to add value by increasing our interest in a core asset, at the same time improving the book value of our overall reserves. (3) The third approach would allow us to acquire pre-existing development properties from small operators. This strategy allows the company to quicken its pace in growing its core asset base and its position in low risk developmental areas that are congruent with our methodology. We are able to pick up infrastructure that is already in place and improve on reserves and

21

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monthly cash flow from existing monthly production and future behind pipe reserves. We would fund programs via private placement as we have always done, however, as a public company, our clients would have a secondary market available as an exist strategy which allows more client flexibility when investing in and existing out of oil and gas projects. We will work with our trusted investor base in large part to raise the investment capital needed for this opportunity. And we will use road shows, trade shows, word of mouth and a network of friends and professionals to secure investment capital. Our two year plan beyond securing the investment capital for future funding of projects will involve the development of broker dealer to handle the funding requirements of our future projects and line of credits will be incorporated long term to facilitate our growth in development wells. Customers Petron Energy’s customers would be gas marketer’s who presently represents the company. Their job is to negotiate the best spot market price for us and execute the sales contract once an agreement is completed. As the company grows in production, we will seek to expand our customer base. The majority of natural gas produced in the Cotton Valley Trend is purchased by end users in the state of Texas. Financial Forecast This financial forecast assume several variables; the interest the company received from trading shares in the company for investor working interest, which will improved the companies cash flow and the investment of $2,000,000.00 @ industry level (cost) participation, which will improve the cash flow of the company while at the same time adding value to our balance sheet and subsequently our share price. We are currently working with one of our industry partners to secure a 25% interest position in 5000 production and developmental acres within the Cotton Valley Trend.

23

These highly coveted acres will allow our active participation in multiple well projects (two vertical wells, one horizontal well or two horizontal wells) with the horizontal well packer plus system budgeted for implementation. This approach allows us to create value in our share price ultimately and improve our cash flow position. Review the use of proceeds section in our Confidential Private Placement Memorandum for breakdown of fund allocation. Operational Plan We presently have adequate office space to house our operational needs. We have a 5 year lease currently on the approximate 3000 feet space. Our offices are positioned on a main thoroughfare in North Dallas (County) Texas at 17950 Preston Road, Suite 960, Dallas, TX 75252. Our business hours are 8:00 a.m. to 5:00 p.m. Our product development involves leasing oil and natural gas minerals in the Cotton Valley Trend in East Texas. This process is achieved by subcontracting the service of Landmen in the various counties of interest to us in East Texas. (see Exhibit R mineral lease contract) Management and Organization Mr. Floyd Smith will manage the day-to-day operations. Mr. Floyd Smith is President of Petron Energy, Inc. He has 15 years experience in the energy industry. As a graduate of Harding University in Searcy, AR., Mr. Smith has a diverse background. He spent eight years with Wal-Mart Stores (store director for five years). While there he learned the essentials of business operations and people management. After retiring from Wal-Mart, Mr. Smith was introduced to the energy industry, over a six-year span; he started as an assistant broker and worked his way up to a senior level manager. During that time he was a top producer for the organization. He became well versed in client relations, product marketing, log analysis, completions, drilling operations and well rework operations. In 1998 he founded Petron Energy, Inc. His efforts have been focused on operations and investor relations of oil and gas project/properties for Petron

24

Energy investors. Through Mr. Smith’s efforts, Petron Energy, Inc. has amassed client relationships from industry partners, private estates, trusts and individual investors. Since Petron Energy’s inception, it has participated in approximately 46 wells through the funding of approximately $14,000,000 in equity capital from its investors. Our corporate attorney is Richard “Dick” Hewitt; Dick has worked with the U.S. Securities and Exchange Commission (“S.E.C.”) in varying legal positions including Chief Enforcement Attorney for 15 years prior to starting R.M. Hewitt P.C.. During his career with the S.E.C., Mr. Hewitt investigated numerous oil and gas fraud cases in the Southwest. He has been in private practice of 26 years. Dick is responsible for Petron Energy’s security and legal duties. Our corporate accountant is Nathan Reeder, CPA; Nathan has been CPA specializing in oil and gas accounting for roughly 50 years. He has been a proven asset to our organization during our 10 year association. Nathan attended SMU. Nathan currently performs oil and gas accounting for clients domestically and internationally. Petron Energy has consulted its geological and petroleum engineering works in the past and will eventually need to hire a geologist and petroleum engineer for its future developmental opportunities. As the company seeks to acquire leases, it will eventually need to add a landman to its staff. Mike Hoover has been a trusted friend and oil and gas consultant and advisor. Mike has over 25 years of oil and gas experience in all aspects of geological, engineering, geophysical, property management, log analysis and well operations. He is a graduate of Abilene Christian University. Larry Crain has been a trusted friend and consultant. Larry has over 20 years of oil and gas experience in operations and investor relations. He is a graduate of University of Texas at Arlington. Tom Kidd has been a trusted friend and consultant. Tom has over 35 years of oil and gas experience in field operations, well completion, log analysis and well operations. Tom is a graduate of Bradley University. Robert Sparks has been a trusted friend consultant and advisor. Robert has over 25 years of oil and gas experience in acquisition, development,

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exploration and operation of oil and gas properties. Robert is a graduate of Lamar University. Economic and Future Outlook The energy market is coming off a 2006 year which saw activity indicators hit 21 year highs. With higher prices, company revenue grew consistently. Oil futures have cooled down between $55 and $58/bbl for West Texas intermediate as of mid-November. Average futures from January through September were 68.22/bbl. Operators have enjoyed very attractive revenue for most of 2006. Natural gas has seen softened prices due to the mild winter for 2006 verses 2005. As of November 2006, U.S. storage levels are up 7.4% from their five year averages. Prices have cooled somewhat because of this, wellhead prices are down 15%, 6.51mcf/d verses 7.68mcf/d in August 2005. Due to the hurricanes of 2005, we saw a 54% decline in gas prices in comparing October 2005 to October 2006. Between 2000 and 2020, U.S. natural gas demand is projected by the Energy Information Administration to increase by more than 50 percent, from 22.8 to 34.7 trillion cubic feet. More than half of the increase in overall gas consumption will result from rising demand for electricity generation. The projected rise in domestic natural gas production – from 19.3 trillion cubic feet in 2000 to 29.0 trillion cubic feet in 2020 – may not be high enough to meet projected demand. The most significant long-term challenge relating to natural gas is whether adequate supplies can be provided to meet sharply increased projected demand at reasonable prices. If supplies are not adequate, the high natural gas prices experienced over the past years could become a continuing problem. To meet this long-term challenge, the United States not only needs to boost production, but also must ensure that the natural gas pipeline network is expanded to the extent necessary. Consumption of natural gas worldwide increased from 95 trillion cubic feet in 2003 to 182 trillion cubic feet in 2030 in the IEO2006 reference case. Although natural gas is expected to be an important fuel source in the

26

electric power and industrial sectors, the annual growth rate for natural gas consumption in the projections is slightly lower than the growth rate for coal consumption—in contrast to past editions of the IEO. Higher world oil prices in IEO2006 increase the demand for and price of natural gas, making coal a more economical fuel source in the projections. Natural gas consumption worldwide increases an average rate of 2.4 percent annually from 2003 to 2030. Coal increases an average rate of 2.5 percent per year and 1.4 percent per year for oil. Nevertheless, natural gas remains a more environmentally attractive energy source and burns more efficiently than coal, and it still is expected to be the fuel of choice in many regions of the world. As a result, the natural gas share of total world energy consumption (on a Btu basis) grows from 24 percent in 2003 to 26 percent in 2030. Worldwide, the industrial and electric power sectors are the largest consumers of natural gas. In 2003, the industrial sector accounted for 44 percent and the electric power sector 31 percent of the world’s total natural gas consumption. In the projections, natural gas use grows by 2.8 percent per year in the industrial sector and 2.9 percent per year in the electric power sector from 2003 to 2030. In both sectors, the share of total energy demand met by natural gas grows over the projection period. In the industrial sector, natural gas overtakes oil as the dominant fuel by 2030. In the electric power sector, however, despite its rapid growth, natural gas remains a distant second to coal in terms of share of total energy use for electricity generation. (see Exhibit Q)

Capitalization We are raising $5 million dollars in working capital to be dispensed as follows:

USE OF PROCEEDS (200 Units)

Source of Funds:

Amount Percent

Purchase of Units consisting of Series A Preferred Stock and Class A Warrants

$5,000,000

100%

Amount

PercentPer Unit

Invest In Development Gas and Oil Wells $2,000,000 40.0% $10,000 Purchase Oil and Gas Leases 1,000,000 20.0% 5,000 Legal, Accounting, and Printing Costs 25,000 .5% 125 Exchange Program Working Capital

800,000 750,000

16.0% 15.0%

4,000 3,750

Interest Reserve 300,000 6.0% 1,500 Syndication Costs 125,000 2.5% 625

Totals: $5,000,000 100.0% $25,000 There may be some changes in the use of proceeds authorized by the Board of Directors depending upon various factors related to the success of drilling the developmental wells and also the availability of high quality oil and gas leases. 27

Petron Energy3 Year Cashflow Projections

By Month

Time period

Pre Start Jan-08 Feb-08 Mar-08 Apr-08 May-08 Jun-08 Jul-08 Aug-08 Sep-09 Oct-08 Nov-08 Dec-08CASH

Beginning cash balance 4,075,000 3,510,009 3,445,018 3,380,027 2,865,036 2,850,045 2,835,054 2,370,063 2,405,072 2,440,081 524,590 609,099Revenue 50,000 50,000 50,000 100,000 100,000 100,000 150,000 150,000 150,000

Total available cash 0 4,075,000 3,510,009 3,445,018 3,430,027 2,915,036 2,900,045 2,935,054 2,470,063 2,505,072 2,590,081 674,590 759,099

LESS

Cost of Goods 515,000 15,000 15,000 515,000 15,000 15,000 515,000 15,000 15,000 515,000 15,000 15,000Operating Expenses 49,991 49,991 49,991 49,991 49,991 49,991 49,991 49,991 49,991 50,491 50,491 50,491

Land Leases 1,500,000 Purchase Shell Company 800,000

Syndication Costs 125,000

Total disbursements 925,000 564,991 64,991 64,991 564,991 64,991 64,991 564,991 64,991 64,991 2,065,491 65,491 65,491

Cash balance (925,000) 3,510,009 3,445,018 3,380,027 2,865,036 2,850,045 2,835,054 2,370,063 2,405,072 2,440,081 524,590 609,099 693,608

ADD

Line of Credit Long-term loans

Capital stock issues 5,000,000 Total additions 5,000,000 0 0 0 0 0 0 0 0 0 0 0 0

Ending cash balance 4,075,000 3,510,009 3,445,018 3,380,027 2,865,036 2,850,045 2,835,054 2,370,063 2,405,072 2,440,081 524,590 609,099 693,608

Petron Energy3 Year Cashflow Projections

By Month

Time period

Jan-09 Feb-09 Mar-09 Apr-09 May-09 Jun-09 Jul-09 Aug-09 Sep-09 Oct-09 Nov-09 Dec-09CASH

Beginning cash balance 693,608 641,608 749,608 907,608 55,608 363,608 671,608 19,608 527,608 1,035,608 583,608 1,291,608Revenue 1,540,000 200,000 250,000 1,740,000 400,000 400,000 1,940,000 600,000 600,000 2,140,000 800,000 800,000

Total available cash 0 2,233,608 841,608 999,608 2,647,608 455,608 763,608 2,611,608 619,608 1,127,608 3,175,608 1,383,608 2,091,608

LESS

Cost of Goods 2,530,000 30,000 30,000 2,530,000 30,000 30,000 2,530,000 30,000 30,000 2,530,000 30,000 30,000Operating Expenses 62,000 62,000 62,000 62,000 62,000 62,000 62,000 62,000 62,000 62,000 62,000 62,000Repay Line of Credit 1,000,000

Total disbursements - 2,592,000 92,000 92,000 2,592,000 92,000 92,000 2,592,000 92,000 92,000 2,592,000 92,000 1,092,000

Cash balance 0 (358,392) 749,608 907,608 55,608 363,608 671,608 19,608 527,608 1,035,608 583,608 1,291,608 999,608

ADD

Line of Credit 1,000,000 Long-term loans

Capital stock issues Total additions - 1,000,000 0 0 0 0 0 0 0 0 0 0 0

Ending cash balance 0 641,608 749,608 907,608 55,608 363,608 671,608 19,608 527,608 1,035,608 583,608 1,291,608 999,608

Petron Energy3 Year Cashflow Projections

By Month

Time period

Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10CASH

Beginning cash balance 999,608 (284,142) 417,108 1,118,358 34,608 935,858 2,062,108 1,403,358 2,727,608 4,273,858 4,035,108 5,781,358Revenue 4,015,000 1,000,000 1,000,000 4,215,000 1,200,000 1,425,000 4,640,000 1,625,000 1,850,000 5,065,000 2,050,000 2,275,000

Total available cash 0 5,014,608 715,858 1,417,108 5,333,358 1,234,608 2,360,858 6,702,108 3,028,358 4,577,608 9,338,858 6,085,108 8,056,358

LESS

Cost of Goods 5,100,000 100,000 100,000 5,100,000 100,000 100,000 5,100,000 100,000 100,000 5,100,000 100,000 100,000Operating Expenses 198,750 198,750 198,750 198,750 198,750 198,750 198,750 200,750 203,750 203,750 203,750 203,750

Total disbursements - 5,298,750 298,750 298,750 5,298,750 298,750 298,750 5,298,750 300,750 303,750 5,303,750 303,750 303,750

Cash balance 0 (284,142) 417,108 1,118,358 34,608 935,858 2,062,108 1,403,358 2,727,608 4,273,858 4,035,108 5,781,358 7,752,608

ADD

Line of Credit Long-term loans

Capital stock issues Total additions - 0 0 0 0 0 0 0 0 0 0 0 0

Ending cash balance 0 (284,142) 417,108 1,118,358 34,608 935,858 2,062,108 1,403,358 2,727,608 4,273,858 4,035,108 5,781,358 7,752,608

EARNINGS PER SHARE WORKSHEET 2008 2009 2010 2011 2012

Net Profit (3,381,396) 256,000 6,753,000 27,337,500 47,465,000

Outstanding Shares 65,000,000 65,000,000 65,000,000 65,000,000 65,000,000 Earnings Per Share (.05) .003 .10 .42 .73 Value of Share (.003) .05 1.50 6.30 10.95 These projections are estimates only and not to be intended as guaranteed performances.

Petron Energy 3 Year Operating Projections

By Month

Assumptions:

Petron will do a minimum of 8 industry deals between 2008-2010. Each deal represents 3 wells. Each deal will cost $500k to participate. Return on investment should begin in the 4th month after the investment at a monthly rate of $50k.

Petron will seek a line of credit for one half of the cost to do each industry deal of $500k.

Petron will lease 7,500 acres of land at a estimated cost of $200 per acre to pursue the drilling of vertical and horizontal wells. The rights to the leases should be complete by the fall of 2008.

The first 8 Petron Wells will be 2 vertical wells per deal at an estimated cost of $2,000,000 per well. Petron will keep a 50% stake in each of its deals and sell the remaining 50% in retail packages. Retail packages are turnkey in structure and have contingenciesfactored into the cost of the project. Wells will begin in 2009.

Gross monthly income from Petron Wells are estimated at $375k per month. A total of 24 wells will be done over a 24 month period beginning in 2010. Revenue should begin in the 4th month after each deal (3 wells) is done.

Each Petron well is a 3 well project consisting of 2 vertical and 1 horizontal. Vertical wells estimated operating expenses are $5k per month.Horitzonal wells are estimated at $20k per month.

Field labor represents the following: Engineer - $65k, geologist - $65k, Land manager - $50k, executive administrator - $50kThe position for land manager will not be filled until 2009 along with other increases in field staff.

Horizontal wells will cost $5,000,000. each to do. Expected drillings for these types will begin in 2010.

Payroll for the office include the management team, administrative support, public relations coordinator, accounting, etc.

Petron Energy 3 Year Operating Projections

By Month1 deal 1 deal 1 deal 1 deal 4 wells

Income Jan-08 Feb-08 Mar-08 Apr-08 May-08 Jun-08 Jul-08 Aug-08 Sep-08 Oct-08 Nov-08 Dec-08 TotalIndustry Deals - - - 50,000 50,000 50,000 100,000 100,000 100,000 150,000 150,000 150,000 900,000 Petron WellsRetail PackagesTotal Income - - - 50,000 50,000 50,000 100,000 100,000 100,000 150,000 150,000 150,000 900,000

COGS Field Labor 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 180,000 Petron Wells 1,500,000 1,500,000 Industry Deals 500,000 500,000 500,000 500,000 2,000,000 Total COGS 515,000 15,000 15,000 515,000 15,000 15,000 515,000 15,000 15,000 2,015,000 15,000 15,000 3,680,000

Gross Profit (515,000) (15,000) (15,000) (465,000) 35,000 35,000 (415,000) 85,000 85,000 (1,865,000) 135,000 135,000 (2,780,000)

Operating ExpensesPayroll 27,083 27,083 27,083 27,083 27,083 27,083 27,083 27,083 27,083 27,083 27,083 27,083 324,996 Payroll Tax 4,208 4,208 4,208 4,208 4,208 4,208 4,208 4,208 4,208 4,208 4,208 4,208 50,500 Advertising 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 24,000 Office expenses 500 500 500 500 500 500 500 500 500 500 500 500 6,000 Telephone 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,500 1,500 1,500 13,500 Insurance 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 12,000 Legal Expenses 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 48,000 Accounting 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 36,000 Vehicle(s) 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 2,000 24,000 Rent 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 30,000 Interest Expense - - - - - - - - - - - - - Postage/Shipping 300 300 300 300 300 300 300 300 300 300 300 300 3,600 Depreciation - - - - - - - - - - - - - Misc 400 400 400 400 400 400 400 400 400 400 400 400 4,800 Travel 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 18,000 Equipment Rental 500 500 500 500 500 500 500 500 500 500 500 500 6,000 Total Expenses 49,991 49,991 49,991 49,991 49,991 49,991 49,991 49,991 49,991 50,491 50,491 50,491 601,396

Net Profit b/tax (564,991) (64,991) (64,991) (514,991) (14,991) (14,991) (464,991) 35,009 35,009 (1,915,491) 84,509 84,509 (3,381,396)

Petron Energy 3 Year Operating Projections

By Month1 deal 1 deal 1 deal 1 deal 12 wells

Income Jan-09 Feb-09 Mar-09 Apr-09 May-09 Jun-09 Jul-09 Aug-09 Sep-09 Oct-09 Nov-09 Dec-09 TotalIndustry Deals 200,000 200,000 200,000 250,000 250,000 250,000 300,000 300,000 300,000 350,000 350,000 350,000 3,300,000 Petron Wells 150,000 150,000 150,000 300,000 300,000 300,000 450,000 450,000 450,000 2,700,000Retail Packages 1,340,000 1,340,000 1,340,000 1,340,000 5,360,000Total Income 1,540,000 200,000 200,000 1,740,000 400,000 400,000 1,940,000 600,000 600,000 2,140,000 800,000 800,000 11,360,000

COGS Field Labor 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 300,000 Petron Wells 2,000,000 2,000,000 2,000,000 2,000,000 8,000,000 Industry Deals 500,000 500,000 500,000 500,000 2,000,000 Cost of Operation 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 60,000 Total COGS 2,530,000 30,000 30,000 2,530,000 30,000 30,000 2,530,000 30,000 30,000 2,530,000 30,000 30,000 10,360,000

Gross Profit (990,000) 170,000 170,000 (790,000) 370,000 370,000 (590,000) 570,000 570,000 (390,000) 770,000 770,000 1,000,000 Operating ExpensesPayroll 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 30,000 360,000 Payroll Tax 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 5,500 66,000 Advertising 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 36,000 Office expenses 500 500 500 500 500 500 500 500 500 500 500 500 6,000 Telephone 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 36,000 Insurance 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 14,400 Legal Expenses 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 60,000 Accounting 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 48,000 Vehicle(s) 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 3,500 42,000 Rent 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 30,000 Interest Expense - - - - - - - - - - - - - Postage/Shipping 400 400 400 400 400 400 400 400 400 400 400 400 4,800 Depreciation - - - - - - - - - - - - - Misc 400 400 400 400 400 400 400 400 400 400 400 400 4,800 Travel 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500 30,000 Equipment Rental 500 500 500 500 500 500 500 500 500 500 500 500 6,000 Total Expenses 62,000 62,000 62,000 62,000 62,000 62,000 62,000 62,000 62,000 62,000 62,000 62,000 744,000

Net Income b/tax (1,052,000) 108,000 108,000 (852,000) 308,000 308,000 (652,000) 508,000 508,000 (452,000) 708,000 708,000 256,000

Petron Energy 3 Year Operating Projections

By Month1 1 1 1 4

Income Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10 TotalIndustry Deals 400,000 400,000 400,000 450,000 450,000 450,000 500,000 500,000 500,000 550,000 550,000 550,000 5,700,000 Petron Wells 600,000 600,000 600,000 750,000 750,000 975,000 1,125,000 1,125,000 1,350,000 1,500,000 1,500,000 1,725,000 12,600,000Retail Packages 3,015,000 3,015,000 3,015,000 3,015,000 12,060,000Total Income 4,015,000 1,000,000 1,000,000 4,215,000 1,200,000 1,425,000 4,640,000 1,625,000 1,850,000 5,065,000 2,050,000 2,275,000 30,360,000

COGS Field Labor 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 600,000 Petron Wells 4,500,000 4,500,000 4,500,000 4,500,000 18,000,000 Industry Deals 500,000 500,000 500,000 500,000 2,000,000 Cost of Operations 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 600,000 Total COGS 5,100,000 100,000 100,000 5,100,000 100,000 100,000 5,100,000 100,000 100,000 5,100,000 100,000 100,000 21,200,000

Gross Profit (1,085,000) 900,000 900,000 (885,000) 1,100,000 1,325,000 (460,000) 1,525,000 1,750,000 (35,000) 1,950,000 2,175,000 9,160,000 Operating ExpensesPayroll 75,000 75,000 75,000 75,000 75,000 75,000 75,000 75,000 75,000 75,000 75,000 75,000 900,000 Payroll Tax 12,500 12,500 12,500 12,500 12,500 12,500 12,500 12,500 12,500 12,500 12,500 12,500 150,000 Advertising 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 20,000 20,000 20,000 20,000 200,000 Office expenses 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500 18,000 Telephone 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 60,000 Insurance 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 120,000 Legal Expenses 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 25,000 300,000 Accounting 20,000 20,000 20,000 20,000 20,000 20,000 20,000 22,000 20,000 20,000 20,000 20,000 242,000 Vehicle(s) 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 180,000 Rent 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 120,000 Interest Expense - - - - - - - - - - - - - Postage/Shipping 750 750 750 750 750 750 750 750 750 750 750 750 9,000 Depreciation - - - - - - - - - - - - - Misc 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 12,000 Travel 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 60,000 Equipment Rental 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 36,000 Total Expenses 198,750 198,750 198,750 198,750 198,750 198,750 198,750 200,750 203,750 203,750 203,750 203,750 2,407,000

Net Income b/tax (1,283,750) 701,250 701,250 (1,083,750) 901,250 1,126,250 (658,750) 1,324,250 1,546,250 (238,750) 1,746,250 1,971,250 6,753,000

Petron Energy2 Year Operating Projections

By Year

Sales Year 4 Year 5Industry Deals 8,100,000 10,500,000Petron Wells 30,150,000 48,150,000Retail Packages 12,060,000 12,060,000

Total Sales 50,310,000 70,710,000

COGSField Labor 675,000 750,000Petron Wells 18,000,000 18,000,000Industry Deals 2,000,000 2,000,000Cost of Field Operations 600,000 600,000

Total COGS 21,275,000 21,350,000

Gross Profit 29,035,000 49,360,000

Operating ExpensesPayroll 1,000,000 1,200,000Payroll Tax 167,500 195,000Advertising 250,000 300,000Office expenses 20,000 25,000Telephone 65,000 70,000Insurance 130,000 140,000Legal Expenses 325,000 350,000Accounting 265,000 285,000Vehicle(s) 200,000 200,000Rent 175,000 200,000Interest Expense Postage/Shipping 10,000 12,500Depreciation Misc 15,000 17,500Travel 75,000 100,000Equipment Rental 40,000 45,000Total Expenses 1,697,500 1,895,000

Net Income b/tax 27,337,500 47,465,000

Exhibits

PETRON ENERGY, INC. Cotton Valley Trend

www.petronenergy.net

traditional frac job

slick water only

hybrid slick water

the fracturing fl uid. These materials are called proppants. The proppant enters the fractures in the formation and, when pumping is stopped and the pressure allowed to dissipate, the proppant remains in the fractures. Since the fractures try to close back together aft er the pres-sure on the well is released, the proppant is needed to hold or prop the fractures open. These propped-open fractures provide passages for oil or gas to fl ow into the well.

A series of studies and experimentation in the design of frac treatments have improved de-velopment and stimulation practices in the Sandstone formations of East Texas. Advanced hydraulic fracture diagnostics and documented production results over the fi rst six months of well life have been used to bett er understand fracture geometry and well performance. The objective of the diagnostics is to improve fracture length and optimize fracture treatment de-sign. The resulting changes to completion and stimulation design have resulted in improved well performance.

New Hybrid Fracs Optimize Development In Sand FormationsWhen sandstone rocks contain oil or gas in commercial quantities, recovery can be vastly improved by a process called fracturing which is used to increase permeability to its optimum level. Basically, to fracture a formation, a fracturing service company pumps a specifi cally blended fl uid down the well and into the formation under great pressure. Pumping continues until the formation literally cracks open. Meanwhile, a special type of frac sand is mixed into

Exhibit A

www.petronenergy.net

PETRON ENERGY, INC. Cotton Valley Trend

Tax Benefi ts Of Oil And Gas Investment

For the individual investor not subject to the alternative minimum tax, there are some potentially signifi cant tax advantages arising from development of domestic oil and gas prospects. These benefi ts are manifested in two distinct tax att ributes: the election to expense intangible drilling costs and the percentage depletion expense.

• The election to expense intangible drilling costs helps the individual investor recoup the original cash investment by off sett ing that expense against other ordinary income. Since a substantial portion of the investment in an oil and gas prospect will be intangible drilling cost, this potential benefi t can be very signifi cant depending on the investors incremental tax rate. This election creates an alternative minimum tax preference item and its eff ect should be considered in advance of making this election. The balance of a participant’s investment will fall into two categories: equipment and leasehold improvements, which should be depreciated over seven years and amortized over ten years respectively.

• The percentage depletion expense is an expense created upon the successful completion of a well and the subsequent production. The gross oil and gas revenue from the well will determine this deduction. Currently the percentage of the gross revenue used for calculating the depletion expense is 15% for light, “sweet crude”. This percentage can rise for heavier oil when the price of oil drops below a specifi ed price. Since the deduction is based on gross revenue, the eff ective taxable rate on net income from the prospect is much lower than other ordinary income. There is a potential alternative minimum tax impact of percentage depletion that should be considered.

Simplifi ed Summary1. Intangible Drilling Costs (IDC) are writt en off 100% against adjusted gross income (taxable income), thus lowering taxable income. IDC can vary from 65% to 95% of total unit cost.

2. Lease And Well Capital Costs (TDC) are principally for equipment such as pumpjacks, tankage, wellheads, etc. and are capitalized and depreciated over seven years.

3. Lease Operating Expense (LOE) is a fully deductible business expense with the exception of additional capitalized equipment.

4. Oil And Gas Production Income (Depletion Allowance) is 15% TAX FREE INCOME (minimum 15%) with the percentage determined annually by the IRS based on average price of crude oil and other factors.

*This is not to be construed as tax advice. Petron recommends the use of a Certifi ed Public Accountant competent in oil and gas matt ers.

Cotton Valley Trend 2006-IV 3-well ProjectOne Unit investment in three wells $ 45,000.00Est. 85% Intangible Drilling Cost (IDC expense) $ 38,250.00 1st year write-off 100% IDC $ 38,250.00 1/7th TDC $ 964.00

Estimated fi rst year write-off $ 39,214.00 *39,214 Write-Off X 35% Tax Bracket = $13,725 in Tax Savings

Exhibit B

www.petronenergy.net

PETRON ENERGY, INC. Cotton Valley Trend

Exhibit C

PETRON ENERGY, INC. Cotton Valley Trend

www.petronenergy.net

PETRON ENERGY, INC. Cotton Valley Trend

www.petronenergy.net

•

Dri

llin

g v

ert

ica

lly

fro

m t

he

su

rfa

ce t

o a

po

int

som

e

wh

ere

ab

ov

e t

he

ta

rge

t re

serv

oir

.

•

Th

en

dri

llin

g b

ea

rs o

ff i

n a

n a

rc t

o i

nte

rse

ct

the

re

serv

oir

at

the

pre

-de

term

ine

d “

en

try

po

int”

.

•

Th

e w

ell

-bo

re t

he

n c

on

tin

ue

s a

t a

ne

ar-

ho

rizo

nta

l

att

itu

de

an

d w

ill

sub

sta

nti

all

y o

r e

nti

rely

re

ma

in

wit

hin

th

e r

ese

rvo

ir.

Hor

izon

tal D

rilli

ngIn

the

Cott

on V

alle

y Tr

end

“We

use

all t

he s

ame

engi

neer

ing

and

serv

ice

com

pani

es th

at th

e m

ajor

s in

the

field

util

ize,

and

we

gain

from

all

thei

r exp

erie

nce.”

“We’

ve d

rille

d so

me

16+

vert

ical

wel

ls in

the

Cott

on V

alle

y Tr

end,

but t

his

has

defin

itely

got

us

exci

ted

abou

t the

pot

entia

l.”

•

Th

e o

bje

cti

ve

is

to e

xp

ose

sig

nfi

can

tly

mo

re

re

serv

oir

ro

ck t

o t

he

we

ll-b

ore

su

rfa

ce t

ha

n c

an

be

ach

iev

ed

dri

llin

g a

co

nv

en

tio

na

l v

ert

ica

l

we

ll.

•

Th

e b

en

efi

ts a

re:

• H

igh

er

pro

du

cti

vit

y o

f th

e r

ese

rvo

ir

• P

rolo

ng

ed

re

serv

oir

co

mm

erc

ial

life

Exhibit D

www.petronenergy.net

PETRON ENERGY, INC. Cotton Valley Trend

30586

31894

33125

33735

30104

3612036132

3187333491

500ftdrillinginfo.com

Haygood #11Devon EnergyCompleted 9/06IP: 6,635 MCF 105 BOPD

Griffith #3Completed 1995148,895 MCF to dateIP: 518 MCF

Griffith #4Completed 1997540,169 MCF to dateIP: 683 MCF

Griffith #5Completed 1998443,712 MCF to dateIP: 434 MCF

Haygood #1Completed 19881.1 BCF to dateIP: 1,111 MCF

McRae #4Completed 1991403,267 MCF to dateIP: 154 MCF

Harvard #1Completed 1979442,623 MCF to dateIP: 595 MCF

Griffith #2Completed 1991269,866 MCF to dateIP: 329 MCF

Initial Production Comparison

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Griffith #2 Griffith #3 Griffith #4 Griffith #5 Haygood #1 Harvard #1 McRae #4 Haygood #11

MC

F P

er

Da

yPanola County, East TexasHorizontal Well Area Map and IP Comparison Graph

Vertical Wells

Ho

riz

on

tal W

ell

PETRON ENERGY, INC. Cotton Valley Trend

www.petronenergy.net

Stratigraphic Column

Lower Cretaceous

Rodessa825’

Upper GloydLimestone

Lower GloydLimestone

DeesSandstone

Upper YoungLimestone

Lower YoungLimestone

Pettit330’

Upper PettitLimestone

Pettit ELimestone

Travis Peak1,730’

UpperSandstone and shale

MiddleSandstone and shale

LowerSandstone and shale

Upper JurassicCotton Valley

1,945’

UpperSandstone and shale

Lower (Taylor)Sandstone and shale

Exhibit E

www.petronenergy.net

PETRON ENERGY, INC. Cotton Valley Trend

Cotton Valley Wells Success RateCotton Valley refers to a prevalent geological

formation rich in natural gas and natural gas liquids

0

10

20

30

40

50

60

70

80

90

100

Cotton Valley Travis Peak Pettit

Su

cc

ess

Ra

te (

%)

0

500

1000

1500

2000

2500

MC

F

S. Henderson

IP Comparison

1977-1999

2005

WellsAverages (IP MCF)

1977-1999 3912005 1,010

Exhibit I

PETRON ENERGY, INC. Cotton Valley Trend

www.petronenergy.net

Ye

ars

12

34

56

78

91

01

11

21

31

41

51

61

71

81

92

0Av

erag

e Pr

oduc

tion

256,

181

146,

759

111,

110

83,5

6275

,449

65,9

3868

,288

70,8

6973

,118

70,9

6569

,946

77,4

9874

,869

66,8

2464

,023

52,7

3348

,632

49,1

5652

,029

58,3

27

% o

f tot

al p

rodu

ctio

n14

.05%

8.05

%6.

09%

4.58

%4.

14%

3.62

%3.

75%

3.89

%4.

01%

3.89

%3.

84%

4.25

%4.

11%

3.66

%3.

51%

2.89

%2.

67%

2.70

%2.

85%

3.20

%

% d

ec o

f pre

v ye

ar25

6,18

142

.71%

24.2

9%24

.79%

9.71

%12

.61%

-3.5

6%-3

.78%

-3.1

7%2.

94%

1.44

%-1

0.80

%3.

39%

10.7

5%4.

19%

17.6

3%7.

78%

-1.0

8%-5

.84%

-12.

10%

1,82

3,37

11,

636,

276

86

Co

tto

n V

all

ey

We

lls

Av

g T

ota

l

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ll P

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g P

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ars

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0 y

ea

rs p

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in D

an

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all

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ms

Le

ase

Are

a

0

50,0

00

100,

000

150,

000

200,

000

250,

000

300,

000

12

34

56

78

910

1112

1314

1516

1718

1920

Ye

ar

MCF Exhibit J

PETRON ENERGY, INC. Cotton Valley Trend

www.petronenergy.net

Cotton Valley Wells Completed in August, 2004 with at least 12 Months of Production History

Most Recent Texas RRC, Dist. 6, East Texas - September, 2005

0

200

400

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1,000

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ORY

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Average 656 MCF/D

*** The above data is based on all Texas RRC, District 6, Cotton Valley Wells completed in August 2004 and have reported production through September 2005. Totals include 13.5 months of production, as to reflect the BTU value of the gas and condensate sales. In addition, the top and bottom 10% of the data set have been excluded from all calculations. [Alpha: Left to Right/

Cotton Valley Wells Completed in August, 2004Texas RRC, Dist. 6, East Texas - September, 2005

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

ORY

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mu

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ve

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s P

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ion

*** The above data is based on all Texas RRC, District 6, Cotton Valley Wells completed in August 2004 and have reported production through September 2005. Totals include 13.5 months of production, as to reflect the BTU value of the gas and condensate sales. In addition, the top and bottom 10% of the data set have been excluded from all calculations.

Average 239,419 Mcf/Gas-Cum.

Exhibit K

www.petronenergy.net

PETRON ENERGY, INC. Cotton Valley Trend

Wh

o p

rod

uc

es

the

ga

s?

Ind

ep

en

de

nts

do

!

:

US

Na

tura

l G

as

Pro

du

cti

on

2Q

-20

05

US

Na

tura

l G

as

Pro

du

cti

on

Bre

ak

do

wn

Inde

pend

ents

72%

Maj

ors

24%

Oth

er4%

US

Na

tura

l Ga

s D

em

an

d2

00

5-2

02

5

2005

2025

3% p

er ye

ar g

row

th in

dem

and

1% p

er ye

ar g

row

th in

supp

ly

Wo

rld

Na

tura

l Ga

s C

on

sum

pti

on

19

70

-20

25

36

53

73

9010

511

8

134

151

020406080100

120

140

160

1970

1980

1990

2001

2010

2015

2020

2025

HIS

TO

RY

/

PR

OJE

CT

ION

S

Trillion Cubic Feet

Curre

nt p

rice

fore

cast

for t

he n

ext 2

0 ye

ars r

ange

from

$5.

50 to

$10

.00

per M

CF

Pro

ject

ed

Ga

s P

rice

s p

er

MC

F

$0.0

0

$2.0

0

$4.0

0

$6.0

0

$8.0

0

$10.

00

$12.

00

2005

2010

2015

2020

2025

EN

ER

GY

, I

NC

.

Exhibit L

www.petronenergy.net

PETRON ENERGY, INC. Cotton Valley Trend

Exhibit M

PETRON ENERGY, INC. Cotton Valley Trend

www.petronenergy.net

271259

259

Martin Lake

Lake Tyler East

Lake Cherokee

Kilgore

Smith County

Upshur CountyHarrison County

Cherokee County

Gregg County

Rusk County

Panola County

Longview

Henderson

Marshall

79

79

80

80

59

20

20

Minden

Brandy BranchCooling Pond

Hallsville

271

Frost-Watkins #1

Choice #1

Grimes #1

Brooks #2

Brooks #1

Gramling #2

Braswell #1

Braswell #4

Braswell #3

Braswell #2

Gramling #1

3310

259

79

Henderson

225

Talley Bottoms #1

Talley Bottoms #3

Hudman #5

Hudman #4

20

Sabine River

BNSFTalley Bottoms #2

Daniels #2

Daniels #1

Crawford #1

Rio #1

Anderson #1Anderson #2

Hudman #6

Frost-Watkins #2HFrost #1

5midrillinginfo.com

Well Locations

Company Well Location

2006 Cotton Valley Permits

County Line

Cotton Valley Trend

10/19/06

Exhibit N

www.petronenergy.net

PETRON ENERGY, INC. Cotton Valley Trend

271259

259

Lake Murvaul

Martin Lake

Lake Tyler East

Lake Cherokee

Kilgore

Smith County

Upshur CountyHarrison County

Cherokee County

Gregg County

Rusk County

Panola County

Longview

Henderson

Marshall

79

79

80

80

59

20

20

Minden

Brandy BranchCooling Pond

Hallsville

271

5midrillinginfo.com

Pipeline Infrastructure

Company Well Locations

Pipeline

Cotton Valley Area

Exhibit O

PETRON ENERGY, INC. Cotton Valley Trend

www.petronenergy.net

SE Longview Prospect Area – 14 Year ActualField

Oak Hill (Cott on Valley)Operator

Anadarko E&p Company Lp

LocationDistrict: 6; Harrison County, Texas

Lease NameLetourneau Gas Unit 4

Gas ID Number135118

Cumulative (since 1990)1,745 MMCF

Wells203-31870 (3)

Exhibit P

www.petronenergy.net

PETRON ENERGY, INC. Cotton Valley Trend

South Henderson Prospect – 25 Year Actual

FieldPod(Cott on Valley)

OperatorKingwood

Resources, Inc.

LocationDistrict: 6; Rusk County, Texas

Lease NameAlexander, Cuba Gas Unit

Gas ID Number81249

Cumulative (since 1979)857 MMCF; 11,036 BO

Wells401-30735 (1)

PETRON ENERGY, INC. Cotton Valley Trend

www.petronenergy.net

Exhibit Q

The State of the World Energy MarketOn World Oil Reserves:“I think they (reserves) are on the decline in the biggest oil fi elds in the world TODAY…” T. Boone Pickens

On World Oil and Gas Prices:“We ought to see $60 per barrel oil by the end of the year (2005), and natural gas prices going to $10 per Mcf.” T. Boone Pickens

“I would estimate prices (gas) would average about $7 through 2008. The rising demand for gas, coupled with fl at production, has tripled prices in the last four years.” Michael Zenker, CAER (Cambridge Energy Research Associates)

“We have exhausted the supply of cheap energy.” Jeff rey Currie, Managing Director, Goldman Sachs & Co.

“Oil (& Gas) consumption remains strong even as petroleum prices approach $60 a barrel, sparking concern that growing demand could spur still higher prices…” Wall Street Journal, June 21, 2005, “Big Thirst for Oil is Unslaked”

On Natural Gas Supply and Demand:“Natural Gas demand in North America is increasing at about 3% per year, whereas supply is increasing at only about 1%.” Natural Gas Prices – Historical and Forecast, Cambridge Energy Research Associates

On Natural Gas Consumption:“Natural Gas is expected to be the fastest growing component of world primary energy consumption…Consumption of Natural Gas is projected to increase by nearly 70 percent between 2001 and 2025.” Energy Information Administration, International Energy Outlook 2004

World Oil & Gas Prices - CurrentNymex Crude Future: $58.49/Bbl – Nymex Henry Hub Future: $7.20/MMBtu Source: Bloomberg.com Energy Prices

World Natural Gas Consumption 1970-2025

36

53

73

90105

118

134

151

0

20

40

60

80

100

120

140

160

1970 1980 1990 2001 2010 2015 2020 2025

HISTORY / PROJECTIONS

Tri

llio

n C

ub

ic F

ee

t