Form S-1

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of the registration statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 check the following box: ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

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

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

The information contained in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and we are not soliciting offers to buy these securities in any jurisdiction where the offer or sale is not permitted.

This is the initial public offering of our common stock. No public market currently exists for our common stock. We are offering all of the shares of common stock offered by this prospectus. We expect the public offering price to be between $ and $ per share.

We intend to apply to list our common stock on The Nasdaq Global Market under the symbol “LUCA.”

Investing in our common stock involves a high degree of risk. Before buying any shares, you should carefully read the discussion of material risks of investing in our common stock in “Risk factors” beginning on page 12 of this prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters may also purchase up to an additional shares of our common stock at the public offering price, less the underwriting discounts and commissions payable by us, to cover over-allotments, if any, within 30 days from the date of this prospectus. If the underwriters exercise this option in full, the total underwriting discounts and commissions will be $ and our total proceeds, after underwriting discounts and commissions but before expenses, will be $ .

The underwriters are offering the common stock as set forth under “Underwriting.” Delivery of the shares will be made on or about , 2011.

We have not authorized anyone to provide any information other than that contained in this prospectus or in any free writing prospectus prepared by or on behalf of us or to which we have referred you. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We are offering to sell, and seeking offers to buy, shares of our common stock only in jurisdictions where such offers and sales are permitted. The information in this prospectus or any free writing prospectus is accurate only as of its date, regardless of its time of delivery or of any sale of shares of our common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

Throughout this prospectus, unless specifically stated otherwise or the context otherwise requires:

(i) when we refer to our Restoration Process, our technology and our treatments, or “to restore” and “to treat,” we are referring to our proprietary bioconversion technology that accelerates and enhances the naturally occurring methanogenic process of native anaerobic microbial communities by circulating a mixture of water and nutrients, which we refer to as our nutrient formulations, into reservoirs using existing oil and natural gas wells;

(ii) when we refer to our ownership or operation of wells and properties, as well as our acquisition or disposition of wells and properties, we are referring to the ownership, operation, acquisition or disposition of an interest in the leasehold estate relating to such properties and a working interest in such wells; and

(iii) when we refer to our units or unit arrangements, we are referring to the fact that we may be required to combine our natural gas leases together into “units” under applicable rules and regulations, allowing us to implement our technology and ensure that owners of the various interests equitably share in costs and production.

Certain industry and market data presented in this prospectus has been derived from data included in various industry publications, surveys and forecasts, including those generated by the EIA, the IEA and the WOGCC. We have assumed the correctness and truthfulness of such data, including projections and estimates, when we use them in this prospectus. You should read our cautionary statement in the section entitled “Special note regarding forward-looking statements.”

Prospectus summary

This summary highlights information contained elsewhere in this prospectus and does not contain all of the information you should consider in making your investment decision. You should read this summary together with the more detailed information, including our consolidated financial statements and the accompanying notes, appearing elsewhere in this prospectus. You should carefully consider, among other things, the matters discussed in “Risk factors,” before making an investment decision.

BUSINESS OVERVIEW

Our company

We are a clean energy company that uses biotechnology to create and sustainably produce natural gas. Our proprietary technology stimulates native microorganisms that reside in subsurface hydrocarbon deposits, such as coal, oil, and organic-rich shales, to accelerate the bioconversion of such resources into methane, the principal component of natural gas, which we produce and sell using existing infrastructure. We believe that our business represents a transformative and disruptive innovation in natural gas creation and production, integrating sophisticated biotechnology with the traditional natural gas business. We have performed extensive lab and field testing over the past eight years, including the deployment of over 500 field level applications of our technology, which we believe have:

proved the efficacy of our technology to economically and sustainably create new methane gas;

demonstrated that additional value can be created from using existing natural gas wells and pipeline infrastructure, potentially extending the economic lives of thousands of wells;

confirmed that water should be conserved and re-used whenever feasible, as it is integral to the biogenic creation of new methane gas; and

demonstrated through extensive testing that the technology is safe to the public and the environment.

Our Restoration Process, a proprietary bioconversion technology, accelerates and enhances the naturally occurring methanogenic process of native anaerobic microbial communities by circulating a mixture of water and nutrients into reservoirs using existing oil and natural gas wells. Anaerobic microbes have lived in subsurface coal, oil and shale deposits for millions of years, feeding on organic matter to create natural gas. This complex microbial gas creation process is susceptible to interruption by various biological and other conditions, including traditional coalbed methane development, whereby drilling and extraction dewaters the coal formations, inhibiting microbial activity and disrupting natural gas creation. Our initial focus is to use our Restoration Process to convert coal into methane by restoring subsurface habitats to enhance the creation and production of natural gas.

Our technology allows us to economically and sustainably create natural gas from current wells, thereby utilizing and extending the life of existing natural gas infrastructure, and minimizing our need for new drilling. We produce this newly created natural gas from existing wells and deliver it to the natural gas market via existing pipelines. Unlike the traditional exploration and production industry’s extraction methods in which production peaks and then steeply declines as stored hydrocarbons are depleted, we believe, based on lab and field results, that our Restoration Process economically and sustainably creates low-cost clean energy for many years. We believe our technology competes favorably with the traditional “hunter/gatherer” style of natural gas development (find, drill, produce, then abandon) by allowing a “farming” style of natural gas creation (restore, feed, grow, then harvest), which continually produces a new crop of natural gas.

Our goal is to be the global market leader in biogenic methane gas creation and production. We anticipate growing our business primarily through acquiring natural gas properties, applying our Restoration Process to create new sustainable sources of natural gas, and producing and selling this natural gas to existing markets. In the future, we may expand our efforts to include oil and organic-rich shales.

Our technology

Our Restoration Process creates methane gas, the simplest hydrocarbon molecule. According to the EIA, methane is the cleanest burning form of natural gas. Most natural gas, including methane, is created by either thermogenic or biogenic geologic processes. Thermogenic generation involves the conversion of deep organic sediment material by extreme pressure and heat into coal, oil or natural gas. In contrast, in biogenic generation, anaerobic microorganisms that have lived in subsurface coal deposits and other hydrocarbon deposits for millions of years, convert carbon and hydrogen-rich organic matter to natural gas as part of naturally occurring processes.

Our Restoration Process is designed to sustain the life processes of naturally occurring microbial communities. We do not introduce foreign microbes, nor do we rely upon genetically-engineered microorganisms. Microbes are already present in coalbed water and are responsible for biogenic methane gas creation. The steps in our Restoration Process include (i) the identification and assessment of underground environments where the native conditions are suitable for microbial life activation and where the biogenic process has been active in the past, (ii) the performance of lab and field studies to assess microbial activation and to identify optimal proprietary nutrient formulations, and (iii) the circulation of such nutrient formulations to target microbes in the underground reservoir to support the creation of new methane.

Our Restoration Process can be applied in two ways.

Our initial field delivery process was based on a “push-pull” method, which is more akin to a batch process. Under the push-pull method, water is withdrawn from the coal seam from surrounding wells. That water is then supplemented with a proprietary nutrient formulation and emplaced, or pushed, into the coal seam by gravity feed down the wellbore being treated. After a predetermined time period, the restored well is returned to production and water is withdrawn, or pulled, from the restoration well, tested, and recirculated into another well or disposed of in another manner, typically by discharging into a surface reservoir.

We are transitioning to a multi-well continuous flow method, referred to as “gas farming.” In gas farming, wells are restored in a manner similar to the push-pull method described above, but instead of restoring a well once, producing the well and waiting several years to treat it a second time, additional nutrient formulations are added within months of the original restoration. Water is temporarily withdrawn from the coal seam in surrounding wells and circulated back into the coal seam via the restoration wells through existing infrastructure, creating a linked system of wells. In this manner, nutrient formulations are continuously introduced into a coal seam via selected wells through gravity feed. In addition to sustainably creating natural gas over a longer period of time, this continuous flow gas farming process has the added benefit of allowing more effective water management, an advantage in areas where water discharge is restricted.

Based on historical results, average incremental daily natural gas production from the push-pull method starts approximately six months following a treatment, grows to a plateau rate of approximately 25 to 30 Mcf of natural gas per day, and remains at this level for several years. We anticipate that a slow decline in production will follow. However, our most comprehensive demonstration project, involving

more than 260 Powder River Basin wells, is now more than four years old, and plateau rates of production appear to be stable with minimal decline. We believe that gas farming will lead to similar, if not greater, rates of natural gas production as nutrients are constantly fed to the microbes over time, leading to sustainable levels of natural gas production.

Our area of operation

Our primary geographic area of activity, and currently the only area in which we own and operate wells, is the Powder River Basin, or the PRB. The greater PRB traverses approximately 90 miles from east to west and 200 miles from north to south, encompassing portions of northeastern Wyoming and southeastern Montana. The PRB, with continuous wide-spread thick coal seams, an extensive natural gas production infrastructure, water chemistry well suited to microbial methane bioconversion, and exceptional permeability for the efficient delivery of nutrients and production of natural gas among wells, has been our primary focus for the past eight years and will play a critical role in our future growth. According to the EIA, the PRB accounts for approximately 42% of the coal production in the United States and is the single largest source of coal mined in the United States.

According to the WOGCC, to date over 30,000 wells have been drilled to develop coalbed methane in the PRB in Wyoming. At present, many coalbed methane operations in the basin are economically challenged and, according to the WOGCC, approximately 12,000 wells are shut-in or dormant as a result of mature, low rate production and current natural gas prices. We believe this situation will present us with a number of opportunities to acquire properties at attractive prices. We presently own and operate over 1,350 wells in the PRB, many of which are currently shut-in, and have over 89,000 gross (75,000 net) acres held by production and approximately 110 miles of associated natural gas gathering pipelines and equipment. Our intent is to expand our present holdings in the PRB through acquisitions of wells, thereby expanding our control of the basin’s significant bioresource.

From 2006 through March 2010, we performed our Restoration Process on over 400 wells in the PRB under a pilot program regulated by the WOGCC. As we moved towards commercialization, new legislation was required to permit the circulation of our nutrient formulations on a commercial scale. Pending the completion of this legislative process, we elected to shut-in a majority of our wells in 2010 to conserve water. The legislation was passed in February 2011 and the rules implementing this legislation are expected to be finalized by the fall of 2011. As a result, we expect to obtain required regulatory approvals in that time frame. Once that process is complete, we expect to resume our Restoration Process on our wells in Wyoming.

Our competitive strengths

Disruptive and proven technology: We believe that our Restoration Process is a transformative and disruptive innovation that allows for the real-time creation of biogenic methane gas in economic quantities from coal, oil and organic-rich shales using existing infrastructure. Unlike many other new clean energy technologies, successful commercialization of our Restoration Process does not depend on the availability of government subsidies or incentives. Our path to commercialization focuses on receiving the required regulatory approvals, increasing natural gas production from our existing wells, and acquiring additional wells to increase commercial scale.

Sustainable production process in the large natural gas market: When our Restoration Process is applied through existing wells to subsurface environments with native conditions suitable for microbial life, we believe our technology has the potential to create a sustainable source of economic natural gas production that will extend the life of the wells for many years. Production declines from traditional

exploration and production, or E&P, require significant capital investment through additional drilling and completion to maintain natural gas production rates. In contrast, we believe our technology effectively creates a “gas farm,” producing a more stable and sustainable supply of natural gas for an extended period of time. Our natural gas will be sold in the global natural gas market, which according to a report published by the IEA in 2011, accounts for approximately 21% of the global energy supply.

Capital light investment profile and superior full-cycle economics vs. traditional E&P: Traditional E&P, particularly in shales, requires significant upfront capital investment for land acquisition, well drilling and completion, and production and transportation infrastructure. In contrast, we have a capital-light deployment strategy, whereby minimal new wells and no new meaningful infrastructure investments are required to implement our Restoration Process, significantly reducing our upfront capital expenditures. As we create natural gas in real-time, we expect increases to our proved reserves and thus use the term “finding and creation” costs to describe the economics of our full cycle acquisition and natural gas creation process over a 10 to 20 year period. We expect our finding and creation costs over time to be significantly lower than the finding and development costs of traditional E&P companies, due to the lack of significant development costs associated with our Restoration Process.

First mover advantage: We began developing our Restoration Process in 2003, with an initial focus on lab research and development activities to prove the concept of accelerated biogenic gas creation. Beginning in 2006, we transitioned from the lab to the field, and have applied our Restoration Process to over 500 wells, including over 400 in the PRB and over 100 in other natural gas producing basins throughout the United States. In addition, we have anaerobically collected and tested samples from over 1,700 oil and natural gas wells from reservoirs in more than 20 producing regions in three countries. These samples have resulted in thousands of DNA samples of microbes and the DNA sequencing of approximately 1,400 samples from the field and approximately 600 samples from laboratory tests to date. We believe that the substantial body of proprietary data, including our intellectual property, and experience obtained from this effort, combined with the advancement of our technology as compared with other biogenic gas creation companies, represents a significant first-mover advantage that will allow us to accelerate decisions relating to well acquisition and treatment.

Clean alternative to traditional E&P: With increasing societal pressures for domestically produced and environmentally friendly energy solutions, natural gas production represents a way to advance energy independence, as it produces lower CO₂ emissions than any other hydrocarbon. Traditional methods of producing natural gas, especially new horizontal wells requiring multiple hydraulic fracturing treatments, may create an environmental concern as they use millions of gallons of fresh water. By conserving water and producing natural gas in a clean and sustainable way, our technology alleviates many of the issues surrounding hydraulic fracturing, minimizes the necessity for new drilling by us, and has minimal impact on natural resources, including ground water.

Abundant resource: Coal represents the most abundant energy resource and the largest concentration of hydrocarbons in the world on which to apply our technology. According to the EIA, recoverable worldwide coal reserves are reported to be in excess of 900 billion short tons, with unrecoverable coal resources estimated to be many times larger. We have determined through field sampling and testing that many coalbeds are particularly well suited for the implementation of our technology, which allows us to access the energy in coal and deliver that energy as natural gas, avoiding the physical mining, transporting and combustion of coal.

Experienced management team: Our management team offers a unique combination of scientific, operational and managerial expertise in biotechnology and traditional E&P. Our senior management team has over 280 years of combined experience and an average of 28 years of experience in the

energy industry. Our management team’s technical expertise includes microbiology, chemistry and biochemistry, engineering, geosciences, and traditional E&P. Our management team also played key roles in the commercialization of dozens of successful large-scale industrial biotechnology and traditional E&P projects.

Our commercialization strategy

Increase natural gas production with an initial focus on the Powder River Basin: Approximately 275 of our wells in the PRB have been restored and are ready for commercial production of biogenic gas in real-time. We are currently working closely with various Wyoming state and federal agencies to obtain the required regulatory approvals necessary for circulation of our nutrient formulations on a commercial scale. We intend to apply our Restoration Process to a number of our wells and incrementally bring additional PRB wells on line beginning in the near future. We expect it will likely take until the end of 2012 to complete the restoration of a majority of our current wells.

Grow by acquisition and consolidation of natural gas properties: In order to achieve commercialization of our technology, we plan to continue to acquire natural gas properties (wells and pipeline infrastructure) and corresponding oil and natural gas rights in close proximity to our existing operations in the PRB, as well as in additional locations in the United States and abroad. Given the geologic permeability of many coal seams, controlling a large, contiguous area of producing wells is key in capturing the newly generated natural gas. Our acquisition strategy will include acquiring low cost late-in-life uneconomic wells producing minimal natural gas, as well as mid-life economic wells producing natural gas quantities that are already cash flow positive.

Develop strategic partnerships: While our technology is proven and available today, its commercialization could be further accelerated and expanded through strategic partnerships with larger companies. A key technical and strategic priority in the near future is to establish a research and development collaboration with a major international resource company. We are currently exploring collaboration opportunities with a number of major oil and natural gas companies and coal companies.

Advance technology to achieve further yield improvements: We use the term Technology To The Field to describe our efforts to achieve further yield improvements from our Restoration Process, leading to greater natural gas production and improved profitability. The unique microbial and geophysical conditions in the coal seams of each natural gas well require customized restoration treatments and water movement technology for effective microbial activation and commercial natural gas creation.

Broaden our technology applications to other areas and fossil fuels: Our technology and processes are applicable to many other natural gas-producing basins, both in the United States and abroad. In addition to our core assets in the PRB, there are a number of other basins that we have either tested or in which we have pilot projects, such as the Black Warrior Basin in Alabama, the San Juan Basin in New Mexico and the Uinta Basin in Utah, as well as other areas in Oklahoma, Kansas and Illinois. We are also interested in areas in Australia, China, India, South Africa, Indonesia, Canada and Europe. While our current focus is on coalbed methane, heavy oils, mature shallow domestic oil fields, and domestic fractured shale fields offer additional significant hydrocarbon reserves on which to apply our Restoration Process in the future.

Our intellectual property

Our success depends in large part on our proprietary technology for which we seek protection under patent, copyright, trademark and trade secret laws. As of the date of this prospectus, we have 12 issued US and foreign patents, two US and foreign patent applications that are currently allowed and awaiting

issuance, and 36 pending US and foreign patent applications. These patents and patent applications are directed to our technology and the specific methods that support our business. We continue to file new patent applications, for which terms extend up to 20 years from the earliest priority filing date in the United States.

Industry overview

Based on global natural gas consumption reported by the IEA, and assuming a five-year average Henry Hub price of $7.02 per MMBtu, we estimate the annual global natural gas market to be approximately $700 billion, of which the US market represents approximately 21%. Natural gas created from our Restoration Process has a distinct advantage over many renewable energy sources, including biofuels, in that it can be sold directly into existing markets using existing infrastructure. Clean, biogenic, domestically-produced natural gas is an accessible and more environmentally friendly energy alternative, which is expected to play an increasing role in advancing both environmental and energy policy goals in the United States. There has been growing concern over CO₂and other emissions that are especially prevalent from burning coal and fuel oil. According to the EIA, methane is the cleanest burning fossil fuel, with approximately 117 lbs. of CO₂ produced per 1 million Btu equivalent of natural gas, compared to 160 lbs. of CO₂ for fuel oil and 200 lbs. for coal.

Typically, natural gas producers sell their natural gas to a variety of purchasers under various length contracts ranging from one day to multi-year at market based prices. Purchasers include pipelines, processors, other producers, banks, marketing and trading companies and other midstream service providers. Primary users of natural gas globally are power companies, which use it for the production of electricity, and utility companies, which distribute it for residential and industrial use. In 2009, 21% of natural gas used in the United States was consumed by residential homes, 27% by industry, 30% for electrical power, and 14% by businesses, with the remainder used in the operation of natural gas production and transportation infrastructure. With over 90% of the natural gas used in the United States coming from North America, natural gas plays an important role in advancing US energy security.

Our technology offers the potential to expand domestic energy production, while minimizing the need to expand the footprint of the oil and natural gas industry’s producing areas. According to the EIA, demand for natural gas in the United States and globally is projected to grow at annual growth rates of 0.5% and 1.9% through 2035, respectively. The IEA has identified several factors that could accelerate growth in demand for natural gas in the coming years, including potentially faster acceptance of compressed natural gas, or CNG, vehicles, recent policy changes in China promoting the production, import and use of natural gas, and a more restricted outlook for nuclear power in the wake of the Fukushima nuclear power plant disaster in Japan.

The EPA regards natural gas as the cleanest burning transportation fossil fuel commercially available today. The IEA estimated that in 2010 there were 100,000 natural gas vehicles operating on American roads, and more than 11 million natural gas vehicles worldwide. The current US administration has endorsed incentives for trucks powered by natural gas. Additionally, the EPA is expected to impose limits on greenhouse gas emissions from US power plants in September 2011. If implemented, such limits could push power companies to replace coal-fired plants with gas-burning ones, which would further increase domestic natural gas consumption.

Summary risk factors

Our business is subject to numerous risks and uncertainties that you should understand before making an investment decision. These risks are discussed more fully in the section entitled “Risk factors” beginning on page 12 of this prospectus. These include:

we are in an early stage of our commercialization and our limited operating history and lack of meaningful revenue generally preclude us from using historical results to forecast operating results;

although we have demonstrated our ability to increase natural gas production in a limited number of wells, the future success of our business depends on our ability to achieve similar results, on a commercially viable basis, by deploying our technology in multiple hydrocarbon basins to restore and sustain production of commercial quantities of natural gas from existing wells in a timely and economic manner;

we may not be able to make effective adjustments for other locales to achieve results consistent with those we have thus far achieved in coal deposits in the PRB;

if the WOGCC or WDEQ imposes terms and conditions that delay or that make the use of our technology more costly than we currently anticipate or that expose us to liabilities to regulatory authorities or third parties in a manner that we do not currently anticipate, our ability to resume operations and successfully develop our business would be adversely affected;

we may be unable to secure the passage of legislation and regulations favorable to our business model in other states or jurisdictions where we expect to deploy our technology;

we must acquire a significant number of wells in order for our technology to be commercially viable;

the law is unsettled as to whether an oil and natural gas lessee has the right to accelerate the natural production of biogenic coalbed methane without authority from the owner of the coal estate;

we may not be able to restore wells in the PRB using our technology if we are unable to obtain a permit from the BLM;

if our leases expire and we are unable to renew the leases, we will lose our right to implement our technology in the related properties;

we could be required to incur substantial expenditures to address concerns of the BLM regarding the impact of our technology on the federal coal estate, including drilling of core holes, to examine the changes in the Btu content of the coal resulting from the implementation of our technology;

if we violate or fail to comply with applicable environmental laws and regulations or with permits required by such laws and regulations, including with respect to water disposal costs, we could be fined or otherwise sanctioned by regulators;

because the costs of developing our technology at a commercial scale are highly uncertain, we cannot reasonably estimate the amounts necessary to successfully commercialize our technology or be certain that additional capital will be available on acceptable terms when needed;

lower prices for natural gas may reduce the amount of gas that we can produce economically or may require us to write down the carrying value of our assets;

while all current coal mining activities appear to be far removed from our properties and we believe the coal in and around our properties is too deep to economically mine under current conditions, we cannot assure you that coal mining will not occur on our properties and limit our operations;

our actual production, revenues and expenditures related to our reserves are likely to differ from our estimates of proved reserves;

we will likely be impacted more acutely by factors affecting our industry in the PRB than we would if our business was more diversified, increasing our risk profile;

third parties may infringe or misappropriate our patents or other intellectual property rights and litigation may be necessary to enforce our intellectual property rights, protect our trade secrets or determine the validity and scope of the proprietary rights of others; and

our pending and future patent applications may not issue as patents or, if issued, may not issue in a form that will provide us with any meaningful protection or any competitive advantage.

Corporate information

We were formed as Clearflame Resources LLC, a Delaware limited liability company, in April 2003 and changed our name to Luca Technologies LLC in July 2004. We converted into a Delaware corporation on April 20, 2007. Our principal executive offices are located at 500 Corporate Circle, Suite C, Golden, Colorado 80401, and our telephone number is (303) 534-4344. Our website address is www.lucatechnologies.com. Information contained on our website is not incorporated by reference into this prospectus, and you should not consider information contained on our website to be part of this prospectus.

Our logos and “LUCA TECHNOLOGIES^®” and other trademarks or service marks of Luca Technologies Inc. appearing in this prospectus are the property of Luca Technologies Inc. This prospectus contains additional trade names, trademarks and service marks of other companies. We do not intend our use or display of other companies’ trade names, trademarks or service marks to imply relationships with, or endorsement or sponsorship of us by, these other companies.

The offering

Common stock offered by Luca

shares (or shares if the underwriters exercise their option to purchase additional shares in full)

Common stock to be outstanding after this offering

shares (or shares if the underwriters exercise their option to purchase additional shares in full)

Proposed Nasdaq Global Market symbol

“LUCA”

Use of proceeds

We currently intend to use all or a portion of the net proceeds of this offering, together with existing cash and cash equivalents, to acquire natural gas properties (wells and infrastructure) in the PRB and additional areas in the United States and abroad, apply our Restoration Process to such properties, and continue research and development efforts to achieve further yield and rate improvements from our technology. We may also use a portion of the net proceeds of this offering to fund working capital and other general corporate purposes, including paying off our secured debt obligations and the costs associated with being a public company. Please see “Use of proceeds.”

Risk factors

See “Risk factors” starting on page 12 of this prospectus for a discussion of factors you should carefully consider before deciding to invest in our common stock.

The number of shares of common stock to be outstanding after this offering is based on shares outstanding as of , 2011 and excludes:

shares of common stock issuable upon the exercise of options outstanding as of , 2011 at a weighted average exercise price of $ per share; and

shares of common stock reserved for issuance under our third amended and restated 2007 equity incentive plan, or the 2007 Plan.

Except as otherwise indicated, all information in this prospectus assumes:

the conversion of all of our outstanding shares of preferred stock into shares of common stock in connection with the consummation of this offering;

the conversion of all of our outstanding preferred stock warrants into shares of common stock in connection with the consummation of this offering;

the conversion of all of our outstanding common stock warrants into shares of common stock in connection with the consummation of this offering;

no exercise of the underwriters’ option to purchase additional shares; and

the filing of our amended and restated certificate of incorporation, which will occur in connection with the consummation of this offering.

Summary historical consolidated financial data

The following summary historical consolidated financial data should be read together with our consolidated financial statements and the accompanying notes appearing elsewhere in this prospectus and “Management’s discussion and analysis of financial condition and results of operations.” The summary historical consolidated financial data in this section is not intended to replace our historical consolidated financial statements and the accompanying notes. Our historical results are not necessarily indicative of our future results.

We derived the consolidated statements of operations data for 2008, 2009 and 2010 and the consolidated balance sheet data as of December 31, 2009 and 2010 from our audited consolidated financial statements appearing elsewhere in this prospectus. The consolidated statements of operations data for the three months ended March 31, 2010 and 2011 and the consolidated balance sheet data as of March 31, 2011 are derived from our unaudited interim consolidated financial statements appearing elsewhere in this prospectus. The unaudited interim financial statements have been prepared on the same basis as the audited annual consolidated financial statements and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to state fairly our financial position as of March 31, 2011 and results of operations for the three months ended March 31, 2010 and 2011. Operating results for the three months ended March 31, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. The data should be read in conjunction with the consolidated financial statements, accompanying notes, and other financial information included herein.


Consolidated statement of operations data:	Years ended December 31,									Three months ended March 31,
Consolidated statement of operations data:	2008			2009			2010			2010			2011
										(unaudited)
	(in thousands, except share and per share data)
Operating revenue	$	5,322		$	3,823		$	2,419		$	851		$	253

Operating expenses
Research and development expense	$	5,224		$	6,832		$	7,757		$	1,929		$	1,359
Lease operating expense		2,967			3,054			4,159			1,119			719
Gathering and transportation expense		770			915			1,437			428			207
Production taxes		421			131			207			72			23
General and administrative expense		2,610			4,374			5,824			1,329			1,739
Depreciation, depletion and amortization		3,293			3,856			2,607			584			444

Total operating expenses	$	15,285		$	19,162		$	21,991		$	5,461		$	4,491

Operating loss	$	(9,963	)	$	(15,339	)	$	(19,572	)	$	(4,610	)	$	(4,238	)
Other income (expense)		184			(63	)		(103	)		(66	)		(31	)

Net loss	$	(9,779	)	$	(15,402	)	$	(19,675	)	$	(4,676	)	$	(4,269	)

Net loss per share of common stock, basic and diluted	$	(1.17	)	$	(1.84	)	$	(2.35	)	$	(0.56	)	$	(0.51	)
Weighted average number of shares of common stock used in computing net loss per share of common stock, basic and diluted								8,383,980						8,407,618
Pro forma net loss per share of common stock, basic and diluted⁽¹⁾							$	(1.01	)				$	(0.22	)
Weighted average number of common shares used in computing pro forma net loss per share of common stock, basic and diluted⁽¹⁾								19,504,547						19,528,185

(1)

Pro forma basic and diluted net loss per share of common stock and weighted average number of shares of common stock used in computing pro forma basic and diluted net loss per share of common stock for the periods presented give effect to the conversion of all of our outstanding convertible preferred stock into common stock on a one-for-one conversion ratio.


Consolidated balance sheet data: (at period end)	December 31, 2009			December 31, 2010			March 31, 2011
							(unaudited)
	(in thousands)
Cash, cash equivalents and investments	$	62,185		$	36,934		$	32,833
Property and equipment, net		13,834			18,938			18,934
Total assets		78,019			60,886			56,617
Current liabilities		3,576			3,539			3,116
Long-term debt		1,368			310			64
Convertible preferred stock		98,468			98,468			98,468
Total stockholders’ deficit		(28,764	)		(47,429	)		(51,121	)

An investment in our common stock involves a high degree of risk. You should consider carefully the risks and uncertainties described below and the other information included in this prospectus, including our consolidated financial statements and accompanying notes, before deciding to invest in our common stock. If any of the following risks or uncertainties actually occur, our business, financial condition and operating results would likely suffer. In that event, the market price of our common stock could decline and you could lose all or part of your investment in our common stock.

We are in an early stage of our commercialization and our limited operating history and lack of meaningful revenue generally preclude us from using historical results to forecast operating results. Our limited operating history also limits our ability to predict the length of time for which our technology can generate new natural gas from existing wells and whether our technology will be able to restore production from hydrocarbon formations in areas where we are not currently operating. Our proposed business strategies described in this prospectus incorporate our management’s current best analysis of potential markets, opportunities and difficulties that face us. We cannot assure you that our underlying assumptions accurately reflect current trends in our industry or that our technology will be successful. Our business strategies may change substantially from time to time or may be abandoned as our management reassesses our opportunities and reallocates our resources. If we are unable to develop or implement these strategies or if our technology is not economically viable, we may never achieve profitability. Even if we do achieve profitability, we cannot predict the level of such profitability and it may not be sustainable.

We have incurred substantial losses to date, anticipate continuing to incur losses in the future and may never achieve or sustain profitability.

We have incurred substantial net losses since our inception, including net losses of $2.1 million, $5.3 million, $9.8 million, $15.4 million and $19.7 million for the years ended December 31, 2006, 2007, 2008, 2009 and 2010, respectively, and $4.3 million for the three months ended March 31, 2011, and we expect these losses to continue. As of March 31, 2011, we had an accumulated deficit of $68.1 million. We expect to incur additional costs and expenses related to the continued development and expansion of our business, including our research and development operations, the continued restoration and operation of our wells, and acquisitions of additional wells. As a result, even if our revenues increase substantially, we expect that our expenses will exceed revenues for the next several years.

Our ability to become and remain profitable will depend on, among other things, our ability to:

The challenges associated with each of these may be extraordinary, and we may not be able to resolve any difficulties that arise in a timely or cost-effective manner, or at all. As a result of the numerous uncertainties associated with our operations, we are unable to predict the extent of any future losses or when we will become profitable, if ever. Even if we do achieve profitability, we may be unable to sustain or increase our profitability in the future.

Although we have demonstrated the ability to increase natural gas production in a limited number of wells in the PRB in Wyoming, the Black Warrior Basin in Alabama and the Uinta Basin in Utah, the future success of our business depends on our ability to achieve similar results, on a commercially viable basis, by deploying our technology in multiple hydrocarbon basins to restore and sustain production of commercial quantities of natural gas from existing wells in a timely and economic manner. We do not know whether these wells can be restored to commercial levels of production as a result of our technology or whether we can sustain such level of production once restored. If our technology fails to create and produce natural gas economically on a commercial scale or in commercial volumes, the commercialization of our technology could be delayed and the associated costs could increase or commercialization may not be possible at all, and as a result, our business, financial condition and results of operations would be materially adversely affected.

Our technology may not achieve overall results consistent with those achieved in coal seams in the PRB.

The largest scale creation of natural gas resulting from the utilization of our technology to date was achieved in coal seams in the PRB. Geological conditions differ from basin to basin, and we expect that differing conditions will require us to adjust the composition of our nutrient formulations to the geological conditions of the particular basin. We may not be able to make effective adjustments for other locales to achieve results consistent with those we have thus far achieved in coal seams in the PRB. Even if we are successful in developing an economical process for converting existing coal seams in other basins into commercial quantities of natural gas, we may not be able to adapt such process to other hydrocarbon deposits, including oil and organic rich shales. Any inability to effectively adjust our nutrient formulations to accommodate other basins or other hydrocarbon deposits will limit the commercial reach of our technology, which could materially adversely affect our business, financial condition and results of operations.

Our ability to successfully resume operations and develop our business may be adversely affected by legislative and regulatory requirements.

Our business is initially focused in the State of Wyoming, where we are generally subject to laws and regulations of state authorities, such as the Wyoming state legislature, the WOGCC and the WDEQ relating to the creation, development, production, distribution and marketing of natural gas, as well as environmental, health and safety matters relating to natural gas development. From 2006 through March 2010, we performed our Restoration Process on over 400 wells in the PRB under a pilot program regulated by the WOGCC. As we moved towards commercializing our technology, new legislation was

required to permit us to circulate our nutrient formulations on a commercial scale. Pending the completion of this legislative process, we elected to shut-in a majority of our wells in 2010 to conserve water, rather than producing natural gas from our previously treated wells in a manner that disposed of water on the surface. Although this legislation was passed in February 2011, it requires the adoption of implementing regulations by the WOGCC which will require that agency to develop rules for a process with which they have a limited history and familiarity and thus increases the challenge to us of effectively anticipating the scope and terms of the new regulations. Wyoming officials project that these regulations will be in place by the fall of 2011, but we cannot assure you that the new regulations will be finally adopted in that time frame. A significant delay in the adoption of regulations in Wyoming would correspondingly delay use of our technology on a commercial scale. If the WOGCC or WDEQ imposes terms and conditions that delay or that make the use of our technology more costly than we currently anticipate or that expose us to liabilities to regulatory authorities or third parties in a manner that we do not currently anticipate, our ability to resume operations and successfully develop our business would be adversely affected. Additional regulations that are adopted in the future may also impose requirements on the use of our technology that could increase the cost or delay development of our business in Wyoming.

As we attempt to expand our operations into other states and, potentially, foreign jurisdictions, we anticipate that we will continue to confront existing legislative and regulatory regimes that are not easily adaptable to our technology. This will likely require us to continue to work with legislators and regulators in order to educate them about our technology and encourage the passage of legislation and regulation needed to facilitate our doing business in states and other jurisdictions outside Wyoming. We may experience delays similar to those, or more onerous than those, we have confronted in Wyoming, and we cannot predict the degree to which we will be successful in overcoming these delays. A failure to secure the passage of legislation and regulation favorable to our business model in any state or other jurisdiction in which we expect to deploy our technology could have a material adverse effect on our business, financial condition and results of operations.

We may be unable to successfully identify, execute or integrate future acquisitions of natural gas properties.

Our initial strategy is to focus on the acquisition of coalbed methane gas wells in basins throughout the United States where we expect the implementation of our technology to restore and sustain natural gas production on a commercial scale. We must acquire a significant number of wells in order for our technology to be commercially viable, as we do not expect to generate significant revenues from any one well. Accordingly, we must identify large numbers of properties that have coal deposits in sufficient quantities, along with biogenic and operational characteristics that are suitable for the application of our technology. There are a limited number of coal formations that we believe are favorable for coalbed methane development and the application of our technology.

Our need to acquire a large number of natural gas properties exposes us to a number of risks. The valuation of properties involves the application of a number of valuation metrics, and we and the owners of these properties may differ regarding the application of these metrics. For instance, when natural gas prices declined precipitously in 2008 and 2009, we found that it was very difficult to come to terms with natural gas interest owners due to different expectations regarding future natural gas prices or the owners’ unwillingness to sell their wells at prices that were substantially below those that were available before natural gas prices fell. In volatile economic times when commodity prices and interest rates, among other factors, can change significantly in short periods of time, there is a greater challenge in coming to terms on these types of properties. In addition, we may overpay for properties based on mistaken assumptions about future economics, which would adversely affect the future return from our

operations. If our technology becomes widely recognized as an effective means of enhancing the productivity of natural gas wells, property owners may increase the value they ascribe to their properties in light of this potential to produce more natural gas than would have been anticipated absent the use of our technology. Some natural gas property owners may also be reluctant or unwilling to sell due to concerns about their potential exposure for plugging and abandonment of wells or other environmental liabilities if we do not meet our obligations.

Further, although we regularly engage in discussions with, and submit proposals to, acquisition candidates, suitable acquisitions may not be available in the future on reasonable terms. Even if we do identify an appropriate acquisition, we may be unable to finance the acquisition. Negotiations of potential acquisitions may require a disproportionate amount of management’s attention and our resources. Even if we complete additional acquisitions, continued acquisition financing may not be available or available on reasonable terms and any acquired properties may not generate sufficient revenues. Our inability to successfully identify, execute or effectively integrate future acquisitions may negatively affect our business, financial condition and results of operations.

Our property acquisitions will require regulatory approvals that could result in delays and increased costs to us.

We will be required to obtain regulatory approval and permits for new properties that we acquire in Wyoming, and subsequently to combine such properties into approved units prior to initiating our Restoration Process. This permitting process could lead to lengthy delays between the time of our acquisition of new properties and our commercial production of natural gas from them. We anticipate that the permits issued by the WOGCC, WDEQ, the BLM and other regulators will require monitoring of the wells and reservoirs, and the requirements for such monitoring could be very costly or overly burdensome. Accordingly, this may reduce revenue from the natural gas produced from our wells. It is possible that we may make an acquisition and find that the regulatory requirements are too costly to allow us to economically produce natural gas from the acquired wells. Whether permitting is economically feasible may not be evident until after we have made the acquisitions.

As our operations expand outside of Wyoming, we may also face similar or more stringent regulation by other state or foreign authorities, which may limit, delay or impede such expansion. We cannot predict how agencies or courts will interpret existing laws and regulations relating to our business and our technology, particularly given the unique aspects of both, nor can we predict the effect of the adoption and interpretation of any new laws and regulations on our business, financial condition and results of operations, which effect may be materially adverse.

Wells, once acquired, may not be appropriate for our purposes or may have liabilities associated with them that may negatively affect our business, financial condition and results of operations.

Although we plan to invest in properties that we believe will result in projects that will add value over time, we cannot guarantee that all of our acquired wells will result in commercially viable projects. The potential of a given property to continue to produce natural gas and to be adaptable to our technology cannot be determined with a high level of precision in advance. We will continue to perform due diligence reviews of the properties we seek to acquire in a manner that we believe is both consistent with practices in the traditional E&P industry and necessary to determine the biogenic characteristics of such properties and the viability of the wells for the application of our technology. However, these reviews are inherently incomplete and cannot assure us of the quality of the wells or of the success of our technology in enhancing production at the wells. It is generally not feasible for us to perform testing of every

individual property or an in-depth review of its related records as part of each acquisition. Even if we are able to complete an in-depth review and sampling of these properties, such a review may not necessarily reveal existing or potential problems or permit us to become sufficiently familiar with the properties to fully assess their potential for successful application of our technology. Even when problems are identified, it may be necessary for us to assume certain environmental and other risks and liabilities to complete the acquisition of such properties. The discovery of any material liabilities associated with our well acquisitions could harm our results of operations and financial condition. Therefore, we cannot assure you that we will recover all or any portion of our investment in well acquisitions.

We may need to resolve conflicts over ownership of the coal estate to employ our technology.

We have acquired natural gas leases in Wyoming from the owners of the natural gas estate and have proceeded with operations under such leases, based on what we believe to be settled law that, with respect to such leases, coalbed methane is part of the natural gas estate. On certain properties, including some of our leased properties in Wyoming, the coal estate and the natural gas estate have different owners. The largest owner of coal in much of the western United States and the PRB is the US federal government. With respect to approximately 33% of our wells in Wyoming, the federal government owns the coal and natural gas estates, while in a majority of the other 67%, the federal government owns the coal and a private entity owns the natural gas estate. The law is not settled as to whether an oil and gas lessee has the right to accelerate the natural production of biogenic coalbed methane without authority from the coal estate. Our technology may be viewed as an acceleration of the naturally occurring process of the conversion of coal to gas and thus could be viewed to burden, damage or, in the absence of federal authorization, trespass on the coal estate. In instances where the federal government is the severed coal estate owner, the BLM or the Office of the Solicitor will likely request us to consider (i) the requirement of additional legal authorization for the impacts to federal coal, (ii) the payment of an impact fee and (iii) an agreement on how to resolve any conflicts that develop with coal mines.

For areas of federally owned coal, we are actively working with the BLM to develop a permit that will allow us to implement our technology in these areas. A prolonged permitting process or overly burdensome permit conditions could delay or prevent implementation of our technology in these areas. Continued development in unresolved split estate ownership locations could subject us to claims for trespass from the coal estate owner. We generally also have obligations to the owner of the natural gas estate to timely develop those interests. Failure to develop these interests in a timely fashion, while resolving the coal estate issue, could jeopardize the leases and cause us to forfeit certain leases that were not timely developed.

The BLM cannot assure us that any agreed resolution of the treatment of the coal estate with respect to our existing acreage in the PRB will be applicable in other areas of the country or other locations within the same basin. In all areas, including Wyoming, the BLM intends to evaluate this issue on a unit-by-unit basis. Therefore, we cannot assure you that we will be able to successfully resolve this issue in every location where the federal government owns the coal estate but not the natural gas estate, even if we are able to successfully implement a permitting process for our existing wells. If we are unable to resolve this issue with regard to new wells obtained in future acquisitions, we would not be able to produce natural gas from those newly acquired wells, which could have a material adverse effect on our business, financial condition and results of operations.

Evaluation of the environmental impact of our technology in connection with the issuance of any permits may lead to significant delays in our ability to commercialize our process.

The National Environmental Policy Act, or NEPA, requires federal agencies to integrate environmental considerations into their decision-making processes by evaluating the environmental impact of their proposed actions, including the issuance of any permits by the BLM that will be required to utilize our technology in the PRB, and assessing alternatives to those actions. In the course of a NEPA evaluation, if an action involved is determined to be major, an environmental assessment will be prepared to assess the potential direct, indirect and cumulative impacts of a proposed federal action. If impacts are considered significant, the BLM will prepare a more detailed Environmental Impact Statement, or EIS, that is made available for public review and comment. The EPA, other federal agencies, and any interested third parties may review and comment on the scoping of the EIS, and the adequacy of any findings set forth in the draft and final EIS. This process can cause significant delays in the issuance of required permits or result in changes to a project to mitigate its potential environmental impact, which could negatively impact the economic feasibility of a proposed project. We may not be able to restore wells in the PRB using our technology until we are able to obtain a permit from the BLM. Any significant delays in the issuance of required permits as a result of NEPA will likely prevent us from employing our technology on a commercial basis, which may have a material adverse affect on our business, financial condition and results of operations.

Certain of our leasehold assets are subject to lease conditions that require us to reestablish production within the next several years.

The majority of our leasehold acreage consists of leases that are past their primary term and have been held by natural gas production operations. Many of our wells are currently shut-in, and thus are not currently producing, and the associated leases have limitations on the length of time they will remain valid while waiting for operations to resume. Our restoration and production plans for these leases are subject to our ability to receive permits from the WDEQ, the WOGCC and the BLM. For instance, if we are restricted by the regulatory scheme in Wyoming from forming units and reestablishing production in these areas, the leases will expire. If our leases expire and we are unable to renew the leases, we will lose our right to implement our technology in the related properties. Additional factors, including costs to implement our technology, production results, availability and cost of capital, production costs, and gathering system and pipeline transportation constraints, could impact our ability to implement our technology and hold these leases.

We may have to incur additional unexpected regulatory costs before we can utilize our technology.

We may be required to incur a variety of regulatory costs in order to utilize our technology. To address concerns of the BLM regarding the impact of our technology on the federal coal estate, we may be required to conduct certain monitoring, including drilling of core holes, to examine the changes in the Btu content of the coal resulting from the implementation of our technology. Such monitoring programs could require substantial expenditures at a time when we have insufficient revenues or other funds to undertake such monitoring programs. If we are required to conduct expensive monitoring programs, we cannot assure you that financing or cash generated by operations will be available or sufficient to meet these requirements. In addition, we will be required to incur expenditures associated with mechanical integrity testing of injection wells under WDEQ and WOGCC regulations. We may also have additional expenditures which we are required to incur to utilize our technology. If any of these requirements is too costly for us to comply with, we may be unable to implement our technology on a commercial basis, which may have a material adverse affect on our business, financial condition and results of operations.

Governmental laws and regulations may have a significant impact on our operations and strategy.

We are subject to regulation by a variety of federal, state and local authorities. Legal requirements are frequently changing and subject to interpretation and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations. We may incur significant liabilities to the government and/or third parties that may require us to incur substantial costs, including costs for remediation of environmental contamination or other issues. These laws and regulations may require us to obtain and comply with a wide variety of licenses, permits, inspections, approvals and other requirements. Both public officials and private individuals may make claims and may seek to enforce applicable laws and regulations. We cannot predict the outcome (financial or operational) of any related license or permit application, litigation or administrative proceedings that may arise.

In addition, the impact on local water supplies and the environment as a result of enhanced natural gas recovery techniques involving the use of injectants has recently been the subject of increased public and governmental concern, including from public interest groups such as the Powder River Basin Resource Council, due in part to the regulatory focus on hydraulic fracturing. We do not currently utilize hydraulic fracturing and have no plans to use this procedure in the immediate future. However, we cannot say with certainty whether it will be necessary to utilize hydraulic fracturing in the future and whether proposed regulations governing hydraulic fracturing could impact our ability to implement our technology. In addition, while our Restoration Process is very different from hydraulic fracturing in that it does not use pressure to inject our nutrient formulations into a coal seam and it does not fracture the hydrocarbon deposits, we cannot predict whether or to what extent environmental concerns over hydraulic fracturing or our technology itself could impact our Restoration Process.

We are subject to environmental laws and regulations and may become subject to additional laws and regulations in the future related to the impact of enhanced natural gas recovery activities on drinking water and other environmental concerns.

We are subject to various federal, state and local environmental and health and safety laws and regulations governing, among other things, the generation, storage, handling, use and transportation of hazardous materials, the emission and discharge of hazardous materials into the ground, air or water, and the health and safety of our employees. If we violate or fail to comply with these laws and regulations or with permits required by such laws and regulations, we could be fined or otherwise sanctioned by regulators.

Our technology involves the use of water and injection of our nutrient formulations to enhance natural gas recovery. This activity is subject to regulation and potential liability under the existing scheme of environmental regulation in the United States, including under the Safe Drinking Water Act, or the SDWA.

In addition, we could be held liable for contamination at or from our current or former properties and any sites we acquire in the future, as well as for contamination at or from third party sites where we dispose or have disposed of waste, regardless of our fault. We have accrued liabilities representing our estimated costs to plug and abandon our current wells that we believe, based on available information, are sufficient, but may need to be increased in the future. We could also be subject to claims from landowners alleging property damage as a result of our operations. Further, we could be held liable for any and all consequences arising out of human exposure to hazardous substances or other environmental damage. Environmental laws are complex, change frequently and have tended to become more stringent

over time. Therefore, we cannot assure you that our costs of complying with current and future environmental and health and safety laws, and our liabilities arising from past or future releases of, or exposure to, hazardous substances will not adversely affect our business, financial condition and results of operations.

Water disposal costs may have a material adverse effect on our business, financial condition and results of operations.

Environmental regulators such as the WDEQ have restrictive regulations applicable to the surface disposal of water produced from coalbed methane production operations. We anticipate that our Restoration Process will reuse the water produced from our production operations and as a result the applicability of surface water disposal regulations to our operations will be limited. However, as a result of the amount of water in the coal seams in certain areas of the PRB, we will likely be required to dispose of some water on the surface. If it is necessary to discharge such water on the surface, we may be required to obtain certain federal, state and local permits to use surface discharge methods. Surface disposal options may have volumetric limitations and require an extensive third-party water sampling and laboratory analysis program to ensure compliance with permit standards. Alternatives to surface disposal of waters, including installing and operating treatment facilities or drilling disposal wells to inject the produced water into the underground rock formations adjacent to the coal seams or lower sandstone horizons, are more expensive than surface disposal. Injection wells are regulated by the WDEQ and the WOGCC in Wyoming, and by other regulators in the other states and jurisdictions in which we may have future operations, and require permits from these various agencies. The costs to dispose of produced water may be significant, which could have a material adverse effect on our business, financial condition and results of operations.

Our operations will be subject to laws and regulations that require us to obtain and maintain specified permits or other governmental approvals regarding compliance with environmental laws, including approvals that control the discharge of materials into the environment, require the removal and cleanup of materials that may harm the environment or otherwise relate to the protection of the environment. Laws and regulations protecting the environment have become more stringent in recent years, and may in some cases impose strict, joint and several liability on an owner or operator of a site, rendering a person liable for environmental damage without regard to negligence, fault or knowledge on the part of such person. Some of these laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. These laws and regulations, the modification or interpretation of existing laws or regulations or the adoption of new laws and regulations could have a material adverse effect on our business, financial condition and results of operations.

We may require substantial additional financing to achieve our goals and to make future acquisitions, and a failure to obtain this capital when needed or on acceptable terms could force us to delay, limit, reduce or terminate our research and development and commercialization efforts.

Since our inception, most of our resources have been dedicated towards research and development, as well as demonstrating the effectiveness of our technology in our labs and in the field. We believe that we will continue to expend substantial resources for the foreseeable future on further developing our technology. Because the costs of developing our technology at a commercial scale are highly uncertain, we cannot reasonably estimate the amounts necessary to successfully commercialize our technology. In addition to capital and resources required to continue developing our technology, we anticipate that we

will also expend resources on operating our existing properties and on the acquisition of additional properties to greatly increase the number of wells we can restore and operate.

Global financial conditions and recent market events have been characterized by increased volatility and a resulting tightening of the credit and capital markets. We cannot assure you that debt or equity financing will be available or sufficient to meet or satisfy our initiatives, objectives or requirements. For example, a decline in the trading price of our common stock from the price at which it is sold in this offering could limit our ability to raise equity financing in the future. Our inability to access sufficient amounts of capital on acceptable terms for our operations could have a material adverse effect on our business, financial condition and results of operations.

Raising additional capital may cause dilution to our existing stockholders, restrict our operations or require us to relinquish rights to our technology.

We may seek additional capital through a combination of public and private equity offerings, debt financings, strategic partnerships and licensing arrangements. To the extent that we raise additional capital through the sale or issuance of equity, warrants or other convertible securities, ownership interests of our stockholders will be diluted, and the terms may include liquidation or other preferences that adversely affect the rights of stockholders. If we raise capital through debt financing, it may involve agreements that include covenants limiting or restricting our ability to take certain actions, such as incurring additional debt, making capital expenditures or declaring dividends. If we raise additional funds through strategic partnerships and licensing agreements with third parties, we may have to relinquish valuable rights to our technology, or grant licenses on terms that are not favorable to us. If we are unable to raise additional funds when needed, we may be required to delay, limit, reduce or terminate our commercialization efforts.

Natural gas prices are volatile, and natural gas prices have been significantly depressed since the middle of 2008. An extended decline in the price of natural gas would likely have a material adverse effect on our business, financial condition and results of operations.

Our future financial condition, revenues, results of operations and future growth, and the carrying value of our properties, will depend primarily on the prices we receive for our natural gas production. Our ability to obtain additional capital on attractive terms will also substantially depend upon natural gas prices. Prices for natural gas have been significantly depressed since the middle of 2008 and future natural gas prices are subject to large fluctuations in response to a variety of factors beyond our control.

We cannot predict future natural gas prices and such prices may decline further. Lower prices may reduce the amount of natural gas that we can produce economically and may require us to write down the carrying value of our assets. We anticipate that in the near term substantially all of our natural gas sales will be made in the spot market or pursuant to contracts based on spot market prices and our sales will not likely be made pursuant to long-term fixed price contracts. Any substantial or extended decline in the prices of or demand for natural gas would have a material adverse effect on our business, financial condition and results of operations.

The mining of coal and activities related to the mining of coal near our operations, including core-hole drilling to determine the extent of coal deposits, may impact our ability to operate in that area. In the event coal is actively mined such that it intersects our natural gas properties, we would be required to plug and abandon such wells, which would lead to a loss of revenues. While all current coal mining activities appear to be far removed from our properties and we believe the coal in and around our properties is too deep to economically mine under current conditions, we cannot assure you that coal mining will not occur on our properties, thereby limiting our operations.

Our risk management and measurement systems and hedging activities might not be effective and could increase the volatility of our results.

To attempt to reduce our price risk, we have entered, and may in the future enter, into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in natural gas prices. The systems we use to quantify commodity price risk associated with our businesses might not always be followed or might not always be effective. Further, such systems do not in themselves manage risk, particularly risks outside of our control, and adverse changes in natural gas prices, volatility, adverse correlation of commodity prices, the liquidity of markets, changes in interest rates and other risks discussed in this prospectus might still adversely affect our financial condition, results of operations and cash flows under applicable accounting rules, even if risks have been identified. Furthermore, no single hedging arrangement can adequately address all commodity price risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist.

Our use of hedging arrangements through which we attempt to reduce the economic risk of our participation in commodity markets could result in increased volatility of our reported results. Changes in the fair values (gains and losses) of derivatives that qualify as hedges under generally accepted accounting principles in the United States, or GAAP, to the extent that such hedges are not fully effective in offsetting changes to the value of the hedged commodity, as well as changes in the fair value of derivatives that do not qualify or have not been designated as hedges under GAAP, must be recorded in our income. This creates the risk of volatility in earnings even if no economic impact to us has occurred during the applicable period. In addition, our hedging arrangements expose us to the risk of financial loss if our production volumes are less than expected.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

In July 2010, federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, was enacted. The Dodd-Frank Act provides for new statutory and regulatory requirements for derivative transactions, including oil and natural gas hedging transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be cleared on exchanges for which cash collateral will be required. The final impact of the Dodd-Frank Act on our hedging activities is uncertain at this time due to the requirement that the Securities Exchange Commission, or the SEC, and the Commodities Futures Trading Commission, or the CFTC, promulgate rules and regulations implementing the new legislation, which has been deferred until December 31, 2011. These new rules and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts or reduce the availability of derivatives. Although we believe the derivative contracts that we enter into should not be materially impacted by position limits and other regulatory requirements, the impact upon our businesses will depend on the outcome of the implementing regulations adopted by the CFTC.

Depending on the rules adopted by the CFTC or similar rules that may be adopted by other regulatory bodies, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures. A requirement to post cash collateral could therefore reduce our ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

We cannot assure you that defects in our title to natural gas properties do not exist.

Title to natural gas properties is often not possible to determine without incurring substantial expense. Although we sometimes commission independent title reviews with respect to certain of our natural gas rights and properties, we cannot assure you that title defects do not exist in these and in other rights and properties we may acquire. If a title defect does exist, it is possible that we may lose all or a portion of the rights or properties to which the title defect relates. Our ownership of certain properties may therefore vary from our records.

We may face strong competition from traditional E&P companies, other biogenic gas creation companies and alternative clean energy companies that may negatively affect our ability to carry on operations.

Factors that affect our ability to compete successfully in the marketplace include:

Our competitors include major integrated oil and natural gas companies, substantial independent energy companies, and affiliates of major interstate and intrastate pipelines and national and local natural gas gatherers, many of which possess greater financial and other resources than we do. Additionally, we also compete against other companies, such as Ciris Energy, Inc., Synthetic Genomics, Inc., and Next Fuel, Inc., which may seek to employ new technology to enhance the bioconversion of hydrocarbon deposits. Finally, our competitors also include alternative clean energy companies that employ other forms of clean technology such as wind, solar, geothermal, hydro and nuclear power and biofuels. If we are unable to successfully compete against our competitors, our business, financial condition and results of operations may be adversely affected.

Our actual production, revenues and expenditures related to our reserves are likely to differ from our estimates of proved reserves. We may experience production that is less than estimated and production costs that are greater than estimated in our reserve report. These differences may be material.

Although the methodologies used to prepare the estimates of our proved natural gas reserves and future net cash flows at May 31, 2011 were audited by Ryder Scott Company, L.P., or Ryder Scott, our independent petroleum and geological engineers, we are ultimately responsible for the preparation of these estimates and for our estimates of our proved natural gas reserves and future net cash flows at December 31, 2010. Reserve engineering is a complex and subjective process of estimating underground accumulations of natural gas that cannot be measured in an exact manner. Estimates of economically recoverable natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:

Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. We cannot assure you that we will not have material differences between our actual production and the production estimated in our reserve reports or that these differences will not be material in the future.

Based on historical data from our field demonstration projects in the PRB, we have assigned proved developed producing reserves to a limited number of wells which are associated with the successful deployment of our Restoration Process. The reserve data assumes that we will make additional capital expenditures to develop and produce our reserves. Although we have prepared estimates of our natural

gas reserves and the costs associated with these reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the actual results will be as estimated. In addition, the recovery of any undeveloped reserves, if applicable, is generally subject to the approval of development plans and related activities by applicable state and/or federal agencies. Statutes and regulations may affect both the timing and quantity of recovery of estimated reserves. Such statutes and regulations, and their enforcement, have changed in the past and may change in the future, and may result in upward or downward revisions to current estimated proved reserves.

You should not assume that the standardized measure of discounted cash flows is the current market value of our estimated natural gas reserves. In accordance with SEC requirements, the standardized measure of discounted cash flows from proved reserves at December 31, 2010 are based on twelve-month average prices and costs as of the date of the estimate. These prices and costs will change and may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by natural gas purchasers or in governmental regulations or taxation may also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor we use when calculating the standardized measure of discounted cash flows for reporting requirements in compliance with accounting requirements is not necessarily the most appropriate discount factor. The effective interest rate at various times and the risks associated with our operations or the natural gas industry in general will affect the accuracy of the 10% discount factor.

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

There are operational risks associated with our Restoration Process and the production, gathering, transporting, processing and treating of natural gas, including:

Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be appropriate. If our operations are located in or near populated areas, including residential areas, commercial business centers and industrial sites, the level of damages resulting from these risks could increase. In spite of our precautions, events such as those described above could have a material adverse effect on our business, financial condition and results of operations, particularly if the event is not fully covered by insurance.

If we cannot manage our growth effectively, we may not become profitable or sustain future profitability.

Businesses that grow rapidly often have difficulty managing their growth. If our technology is successfully deployed in multiple basins and causes us to grow rapidly, we will face challenges to our organization that may strain our management, technical and field personnel and operations. We may misjudge the amount of time or resources that will be required to manage effectively any anticipated or unanticipated growth or activity in our business. We will likely need to expand our management by recruiting and employing experienced executives and key employees capable of providing the necessary support. Shortages of qualified personnel or the inability to obtain and retain qualified personnel can also negatively affect the quality and timeliness of our work. Our ability to manage growth will depend in large part on our ability to continue to enhance our operating, financial and management information systems. If we cannot scale our business appropriately, maintain control over expenses or otherwise adapt to anticipated and unanticipated growth or changes, our business resources may become strained, and we may fail to stay within our budgets or fail to achieve target milestones. We cannot assure you that our management will be able to manage our growth effectively or successfully. Our failure to meet these challenges may cause us to be unprofitable, and your investment could be lost.

Our current business focus is on the creation and production of coalbed methane gas in a limited number of properties, primarily in the PRB. Larger companies have the ability to manage their risks by diversification. However, we currently lack diversification, in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting our industry in the PRB than we would if our business was more diversified, increasing our risk profile. Such factors include fluctuations in prices of natural gas produced from wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells.

Seasonal weather conditions and wildlife restrictions could adversely affect our ability to conduct operations.

Our operations could be adversely affected by weather conditions and wildlife restrictions. In the PRB, certain coalbed methane gas activities cannot be conducted as effectively during the winter months. Winter and severe weather conditions limit and may temporarily halt the ability to operate during such conditions. These constraints and the resulting shortages or high costs could delay or temporarily halt our coalbed methane gas operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations. In addition, a critical habitat designation for certain wildlife under the US Endangered Species Act or similar state laws could result in material restrictions to public or private land use and could delay or prohibit land access or development. The listing of certain species, such as the sage grouse, as threatened and endangered, could have a material impact on our operations in areas where such listed species are found.

In the ordinary course of business, we may become subject to lawsuits or indemnity claims, which could materially and adversely affect our business, financial condition and results of operations.

From time to time, we may in the ordinary course of business be named as a defendant in lawsuits, claims and other legal proceedings. These actions may seek, among other things, compensation for alleged personal injury, workers’ compensation, employment discrimination, breach of contract, property damages, civil penalties and other losses or injunctive or declaratory relief. In the event that such actions

or indemnities are ultimately resolved unfavorably at amounts exceeding our accrued liability, or at material amounts, the outcome could materially and adversely affect our reputation, business and results of operations. In addition, payments of significant amounts, even if reserved, could adversely affect our liquidity position.

We are dependent on key personnel and the loss of some key executive officers and employees, or our inability to attract, retain and motivate additional personnel, could negatively impact our business prospects.

Our future performance depends to a significant degree upon the continued service of key members of management, as well as technical and operations personnel. The loss of one or more of our key personnel could have a material adverse effect on our business. We believe our future success will also depend in large part upon our ability to attract, retain and further motivate highly skilled management and technical and operations personnel. We cannot assure you that we will be able to retain our key employees or that we will be successful in attracting, assimilating and retaining personnel in the future.

We may have difficulty distributing our natural gas production, which could harm our financial condition.

In order to sell the natural gas we will produce utilizing our Restoration Process, we may have to make arrangements for distribution to the market. We will rely on local infrastructure and the availability of transportation for shipment of our natural gas, but infrastructure development and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. This situation could be exacerbated if our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. These factors may affect our ability to acquire and restore properties and to transport our natural gas production, which may increase our expenses.

We may not be able to use some or all of our net operating loss and tax credit carry-forwards to reduce future income taxes.

In general, under Section 382 of the Internal Revenue Code of 1986, as amended, or the Code, as well as applicable state and local income tax laws, a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change net operating loss carry forwards and tax credit carry forwards, or Tax Carryovers, to reduce its income taxes. An ownership change is defined generally for these purposes as a greater than 50% change in ownership by “5% shareholders” over a rolling three-year period. We do not believe that our existing Tax Carryovers are subject to any such limitations, whether arising from prior changes in our stock ownership or changes in stock ownership in connection with this public offering. However, if the Internal Revenue Service or applicable state or local income tax authorities prevail in challenging our analysis, or if we experience an ownership change after this public offering, our ability to utilize our Tax Carryovers could be limited. Future changes in our stock ownership, some of which are outside of our control, could result in such a limitation being imposed. For these reasons, even if we attain profitability we may not be able to utilize our Tax Carryovers to reduce any future income taxes. In addition, our Tax Carryovers expire at various times through 2030 which could also limit their utilization.

Non-US holders of our common stock, in certain situations, could be subject to US federal income tax upon sale, exchange or disposition of our common stock.

We believe we are or are likely to become a US real property holding corporation for US federal income tax purposes. As a result, under the Foreign Investment in Real Property Tax Act, or FIRPTA, certain non-US investors may be subject to US federal income tax on gain from the disposition of shares of our

common stock, in which case they would also be required to file US tax returns with respect to such gain. Whether these FIRPTA provisions apply depends on the amount of our common stock that such non-US investors hold and whether, at the time they dispose of their shares, our common stock is regularly traded on The Nasdaq Global Market or another established securities market within the meaning of the applicable Treasury Regulations. So long as our common stock is listed on an established securities market, only a non-US investor who has held actually or constructively during the shorter of the five-year period ending on the date of disposition or such investor’s holding period more than 5% of our common stock may be subject to US federal income tax on the disposition of our common stock under FIRPTA. See “Certain United States federal income and estate tax consequences to non-US holders.”

If we fail to maintain an effective system of internal controls, we might not be able to report our financial results accurately or timely or prevent fraud; in that case, our stockholders could lose confidence in our financial reporting, which would harm our business and could negatively impact the price of our stock.

Effective internal controls are necessary for us to provide reliable financial reports and prevent fraud. In addition, Section 404 of the Sarbanes-Oxley Act of 2002, or the Sarbanes-Oxley Act, will require us and, in the event we become an accelerated filer, our independent registered public accounting firm, to evaluate and report on our internal control over financial reporting beginning with our Annual Report on Form 10-K for the year ending December 31, 2012. The process of implementing our internal controls and complying with Section 404 will be expensive and time consuming, and will require significant attention of management. We cannot be certain that these measures will ensure that we implement and maintain adequate controls over our financial processes and reporting in the future. Even if we conclude, and our independent registered public accounting firm concurs, that our internal control over financial reporting provides reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, because of its inherent limitations, internal control over financial reporting may not prevent or detect fraud or misstatements. Failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm our results of operations or cause us to fail to meet our reporting obligations. If we or our independent registered public accounting firm discover a material weakness, the disclosure of that fact, even if quickly remedied, could reduce the market’s confidence in our financial statements and harm our stock price. In addition, a delay in compliance with Section 404 could subject us to a variety of administrative sanctions, including SEC action, ineligibility for “short form” securities registration, the suspension or delisting of our common stock from The Nasdaq Global Market and the inability of registered broker-dealers to make a market in our common stock, which would further reduce our stock price and could harm our business.

We may not be able to adequately protect our proprietary information or technology.

Our success depends on our proprietary information and technology. We have adopted an intellectual property strategy, relying on a combination of patents and trade secret laws, as well as on confidentiality and non-compete agreements, in order to establish and protect our proprietary rights. As of the date of this prospectus, we have 12 issued US and foreign patents, two US and foreign patent applications that are currently allowed and awaiting issuance and 36 pending US and foreign patent applications. We have also registered the trademark for LUCA TECHNOLOGIES^® with the US Patent and Trademark Office for use in the United States. Our pending and future patent applications may not issue as patents or, if issued, may not issue in a form that will provide us with any meaningful protection or any competitive

advantage. Even if issued, existing or future patents may be challenged, including with respect to the development and ownership thereof, or narrowed, invalidated or circumvented, which could limit our ability to stop competitors from developing and marketing similar products or limit the length of terms of patent protection we may have for our technology. Further, other companies may design around technology we have patented, licensed or developed. Moreover, changes in patent laws or their interpretation in the United States and other countries could also diminish the value of our intellectual property or narrow the scope of our patent protection.

Third parties may infringe or misappropriate our patents or other intellectual property rights, which could adversely affect our business, financial condition and results of operations, and litigation may be necessary to enforce our intellectual property rights, protect our trade secrets or determine the validity and scope of the proprietary rights of others. In order to protect or enforce our intellectual property rights, we may initiate litigation against third parties, such as infringement suits or interference proceedings. Litigation may be necessary to:

The steps we have taken to deter misappropriation of our proprietary information and technology may be insufficient to protect us, and we may be unable to prevent infringement of our intellectual property rights or misappropriation of our proprietary information. Any infringement or misappropriation could harm any competitive advantage we currently derive or may derive in the future from our proprietary rights. In addition, if we operate in foreign jurisdictions in the future, we may not be able to protect our intellectual property in the foreign jurisdictions in which we operate. The legal systems of certain countries do not favor the aggressive enforcement of intellectual property and the laws of foreign countries may not protect our rights to the same extent as the laws of the United States. Any actions taken in those countries may have results that are different than if such actions were taken under the laws of the United States. Patent litigation and other challenges to our patents are costly and unpredictable and represent a significant diversion of our management’s time and resources. Our intellectual property may also fall into the public domain. If we are unable to protect our proprietary rights, we may be at a disadvantage to others who did not incur the substantial time and expense we have incurred to create our technology.

Confidentiality agreements with employees and others may not adequately prevent disclosures of trade secrets and other proprietary information.

We rely in part on trade secret protection to protect our confidential and proprietary information and processes. However, trade secrets are difficult to protect. We have taken measures to protect our trade secrets and proprietary information, but these measures may not be effective. We require new employees and consultants to execute confidentiality agreements upon the commencement of an employment or consulting arrangement with us. These agreements generally require that all confidential information developed by the individual or made known to the individual by us during the course of the individual’s relationship with us be kept confidential and not disclosed to third parties. These agreements also generally provide that know-how and inventions conceived by the individual in the course of rendering services to us shall be our exclusive property. Nevertheless, these agreements may be breached or may not be enforceable, our proprietary information may be disclosed, and others may independently develop

substantially equivalent proprietary information and techniques or otherwise gain access to our trade secrets and we may not have adequate remedies for any resulting losses. Costly and time-consuming litigation could be necessary to enforce and determine the scope of our proprietary rights, and failure to obtain or maintain trade secret protection could adversely affect our competitive business position.

Our technology may infringe upon the intellectual property rights of others. Intellectual property infringement claims would be time consuming and expensive to defend and may result in limitations on our ability to use the intellectual property subject to these claims.

Claims asserting that we have violated or infringed upon third party intellectual property rights may be brought against us in the future. We may be unaware of intellectual property rights of others that may cover some of our technology or third parties may have or eventually be issued patents on which our current and future technology may infringe. The complexity of the technology involved and the uncertainty of intellectual property litigation increase these risks. Any claims and any resulting litigation could subject us to significant liability for damages. A court could enter orders temporarily, preliminarily or permanently enjoining us from making, using, selling, or importing any current and future technology, or could enter an order mandating that we undertake certain remedial activities. An adverse determination in any litigation of this type could require us to design around a third party’s patent, license alternative technology from another third party, which may not be available on acceptable terms or at all, or reduce or modify our nutrient formulations and Restoration Process. If we could not do these things on a timely and cost-effective basis, our revenues may decrease substantially and we could be exposed to significant liability. In addition, litigation is time-consuming and expensive to defend and could result in limitations on our ability to use the intellectual property subject to these claims.

The market price for our common stock may be highly volatile and you may be unable to sell all of your shares at or above the offering price.

The initial public offering price for our shares will be determined by negotiations between us and representatives of the underwriters and may not be indicative of prices that will prevail in the trading market. The market price of shares of our common stock could be subject to wide fluctuations in response to many risk factors listed in this section, and others beyond our control, including:

Financial markets have recently experienced significant price and volume fluctuations that have affected the market prices of equity securities of companies and that have, in many cases, been unrelated to the operating performance, underlying asset values or prospects of such companies. These broad market and industry fluctuations, as well as general economic, political and market conditions such as recessions, interest rate changes or international currency fluctuations, may negatively impact the market price of our common stock. If the market price of our common stock after this offering does not exceed the initial public offering price, you may not realize any return on your investment in us and may lose some or all of your investment. In the past, companies that have experienced volatility in the market price of their stock have been subject to securities class action litigation and we may be the target of this type of litigation in the future. Securities litigation against us could result in substantial costs and divert our management’s attention from other business concerns, possibly causing serious harm to our business.

A significant portion of our total outstanding shares of common stock is restricted from immediate resale but may be sold into the market in the near future. This could cause the market price of our common stock to drop significantly, even if our business is doing well.

Sales of a substantial number of shares of our common stock in the public market could occur at any time. These sales, or the perception in the market that the holders of a large number of shares of common stock intend to sell shares, could reduce the market price of our common stock. As of , 2011, our directors, executive officers and our four largest stockholders beneficially own, collectively, approximately % of our outstanding common stock, including shares subject to outstanding options. If one or more of them were to sell a substantial portion of the shares they hold, it could cause our stock price to decline. Based on shares outstanding as of , 2011, upon completion of this offering, we will have outstanding shares of common stock, assuming no exercise of the underwriters’ option to purchase an additional shares. As of the date of this prospectus, shares of common stock will be subject to a 180-day contractual lock-up with the underwriters, and shares of common stock will be subject to a 180-day contractual lock-up with us.

In addition, as of , 2011, there were shares subject to outstanding options that will become eligible for sale in the public market upon exercise of such options to the extent permitted by any applicable vesting requirements, the lock-up agreements and Rules 144 and 701 under the Securities Act of 1933, as amended, or the Securities Act. Moreover, after this offering, holders of an aggregate of shares of our common stock will have rights, subject to some conditions, to require us to file registration statements covering their shares or to include their shares in registration statements that we may file for ourselves or other stockholders.

We also intend to register all shares of common stock that we may issue under the 2007 Plan. Once we register these shares, they can be freely sold in the public market upon issuance and once vested and exercised, as applicable, subject to the 180-day lock-up periods under the lock-up agreements described in “Underwriting” elsewhere in this prospectus.

No public market for our common stock currently exists and an active trading market may not develop or be sustained following this offering.

Prior to this offering, there has been no public market for our common stock. An active trading market may not develop following the completion of this offering, or if developed, may not be sustained. The lack of an active market may impair your ability to sell your shares at the time you desire or at the price you desire. The inability to sell your shares in a declining market because of such illiquidity or at a price you desire may substantially increase your risk of loss. Furthermore, an inactive trading market may impair our ability to raise capital to continue to fund our operations by selling shares and may also impair our ability to make acquisitions of other companies or properties by using our shares as consideration.

Purchasers of common stock in this offering will experience immediate and substantial dilution of $ per share.

The initial public offering price will be substantially higher than the tangible book value of our common stock based on the total value of our tangible assets less our total liabilities immediately following this offering. Purchasers of our common stock in this offering will experience immediate and substantial dilution of $ per share as compared to the tangible book value, assuming an initial public offering price of $ per share (the midpoint of the range set forth on the cover of this prospectus). To the extent outstanding options to purchase shares of common stock are exercised, there will be further dilution. See “Dilution” elsewhere in this prospectus.

If our executive officers, directors and largest stockholders choose to act together, they may be able to control our management and operations, acting in their own best interests and not necessarily those of other stockholders.

As of , 2011, after giving effect to this offering, our executive officers, directors and four largest stockholders owned approximately % of our voting stock, including shares subject to outstanding options. As a result, these stockholders, acting together, would be able to significantly influence all matters requiring approval by our stockholders, including the election of directors and the approval of mergers or other business combination transactions. The interests of this group of stockholders may not always coincide with the interests of other stockholders, and they may act in a manner that advances their best interests and not necessarily those of other stockholders. For instance, officers, directors and principal stockholders, acting together, could cause us to enter into transactions or agreements that we would not otherwise consider. Similarly, this concentration of ownership may have the effect of delaying or preventing a change in control of our company otherwise favored by our other stockholders. This concentration of ownership could therefore depress our stock price.

We have broad discretion in the use of our net proceeds from this offering and may not use them effectively.

Our management will have broad discretion in the application of the net proceeds from this offering and could spend the proceeds in ways that do not improve the results of operations or enhance the value of our common stock. You will be relying on the judgment of our management and will not have the opportunity, as part of your investment decision, to assess whether the proceeds are being used appropriately. Our stockholders may not agree with our management’s choices in allocating and spending the net proceeds. These choices could result in additional financial losses that could have a material adverse effect on our business and cause the price of our common stock to decline. See “Use of proceeds” elsewhere in this prospectus.

We will incur significant increased costs as a result of operating as a public company, and our management will be required to devote a substantial amount of time to new compliance initiatives.

We have never operated as a public company. As a public company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. In addition, the Sarbanes-Oxley Act, as well as related rules implemented by the SEC and The Nasdaq Stock Market, impose various requirements on public companies. Our management and other personnel will need to devote a substantial amount of time to these compliance requirements. Additionally, these rules will increase our legal and financial compliance costs and will make certain activities more time-consuming and costly.

In addition, the Sarbanes-Oxley Act requires, among other things, that we maintain effective internal control over financial reporting and disclosure controls and procedures. In particular, we will be required to perform system and process evaluation and testing of our internal control over financial reporting to allow management and our independent registered accounting firm to report on the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act. Our compliance with Section 404 will require that we incur substantial accounting expense and expend significant management time on compliance-related issues. We will need to hire additional accounting and financial staff with appropriate public company experience and technical accounting knowledge. Additionally, if we are unable to comply with Section 404 in a timely manner, our stock price could decline, and we could face sanctions, delisting or investigations by The Nasdaq Stock Market, or other material effects on our business, reputation, results of operations, financial condition or liquidity.

If securities or industry analysts do not publish research or reports about us, our business or our market, or if they make an adverse change regarding our stock, our stock price and trading volume could decline.

The trading market for our common stock will be influenced by the research and reports that industry and securities analysts may publish about us or our industry. If any of these analysts who may cover us change their recommendation regarding our stock adversely, or provide more favorable relative recommendations about our competitors, our stock price would likely decline. If any analyst who may cover us were to cease coverage of our company or fail to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline.

We have not paid, and do not intend to pay dividends on our common stock, so investors should not look to dividends as a source of income.

In the interest of reinvesting profits back into our business, we do not intend to pay cash dividends in the foreseeable future. Consequently, any economic return will initially be derived, if at all, from appreciation in the fair market value of our stock, and not as a result of dividend payments.

We are subject to anti-takeover provisions in our certificate of incorporation and bylaws and under Delaware law that could delay or prevent an acquisition of our company, even if the acquisition would be beneficial to our stockholders.

Provisions in our certificate of incorporation and bylaws, as in effect upon the completion of this offering, may delay or prevent an acquisition of us. Among other things, our certificate of incorporation and bylaws will provide for a board of directors which is divided into three classes, with staggered three-year terms and will provide that all stockholder action must be effected at a duly called meeting of the stockholders and not by a consent in writing, and will further provide that only our board of directors may call a special meeting of the stockholders. These provisions may also frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our board of directors, who are responsible for appointing the members of our management team. Furthermore, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General Corporation Law, which prohibits, with some exceptions, stockholders owning in excess of 15% of our outstanding voting stock from merging or combining with us. Finally, our bylaws will establish advance notice requirements for nominations for election to our board of directors and for proposing matters that can be acted upon at stockholder meetings. Although we believe these provisions together provide an opportunity to receive higher bids by requiring potential acquirers to negotiate with our board of directors, they would apply even if an offer to acquire us may be considered beneficial by some stockholders.

Some of the statements under “Prospectus summary,” “Risk factors,” “Management’s discussion and analysis of financial condition and results of operations,” “Business” and elsewhere in this prospectus constitute forward-looking statements. In some cases, you can identify forward-looking statements by the following words: “may,” “will,” “could,” “would,” “should,” “expect,” “intend,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “project,” “potential,” “continue,” “ongoing,” the negative of these terms or other words that convey uncertainty of future events or outcomes, although not all forward-looking statements contain these words. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, levels of activity, performance or achievements to be materially different from the information expressed or implied by these forward-looking statements. While we believe that we have a reasonable basis for each forward-looking statement contained in this prospectus, we caution you that these statements are based on a combination of facts and factors currently known by us and our projections of the future, about which we cannot be certain. Many important factors affect our ability to achieve our objectives, including:

In addition, you should refer to the “Risk factors” section of this prospectus for a discussion of other important factors that may cause our actual results to differ materially from those expressed or implied by our forward-looking statements. As a result of these factors, we cannot assure you that the forward-looking statements in this prospectus will prove to be accurate. Furthermore, if our forward-looking statements prove to be inaccurate, the inaccuracy may be material. In light of the significant uncertainties in these forward-looking statements, you should not regard these statements as a representation or warranty by us or any other person that we will achieve our objectives and plans in any specified time frame, or at all. You should read this prospectus and the documents that we have filed as exhibits to the registration statement, of which this prospectus is a part, completely and with the understanding that our actual future results may be materially different from what we expect. Further, any forward-looking statement speaks only as of the date on which it is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which the statement is made or to reflect the occurrence of unanticipated events. We qualify all the forward-looking statements contained in this prospectus by the foregoing cautionary statements.

We estimate that we will receive net proceeds of approximately $ million from the sale of shares of common stock offered in this offering based on an assumed initial public offering price of $ per share (the mid-point of the price range set forth on the cover page of this prospectus) and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. A $1.00 increase (decrease) in the assumed initial public offering price of $ per share would increase (decrease) the net proceeds to us from this offering by $ million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. If the underwriters exercise their option to purchase additional shares, we estimate that our net proceeds will be approximately $ million based on an assumed initial public offering price of $ per share (the mid-point of the price range set forth on the cover page of this prospectus).

We currently intend to use all or a portion of the net proceeds of this offering, together with existing cash and cash equivalents, to acquire natural gas properties (wells and infrastructure) in the PRB and additional areas in the United States and abroad, apply our Restoration Process to such properties, and continue research and development efforts to achieve further yield and rate improvements from our technology. We may also use a portion of the net proceeds of this offering to fund working capital and other general corporate purposes, which may include paying off our secured debt obligations and the costs associated with being a public company.

The potential uses of net proceeds from this offering represent our current intentions based upon our present business plans and business conditions. As of the date of this prospectus, we cannot allocate specific percentages of the net proceeds that we may use to fund working capital and for other general corporate purposes.

Until we apply the net proceeds of this offering to its intended uses, we intend to invest the net proceeds in interest-bearing demand deposit accounts or short-term investment-grade securities. We cannot predict whether these temporary investments of the net proceeds will yield a favorable return, or any return at all.

We have never declared or paid cash dividends on shares of our common or preferred stock, and currently do not expect to declare or pay cash dividends in the foreseeable future. We expect to retain our future earnings, if any, for use in the operation and expansion of our business. In addition, the terms of our loan and security agreement with Silicon Valley Bank currently prohibits us from paying cash dividends. Subject to the foregoing, the payment of cash dividends in the future, if any, will be at the discretion of our board of directors and will depend upon such factors as earnings levels, capital requirements, requirements under the Delaware General Corporation Law, restrictions and covenants pursuant to any other credit facilities we may enter into, our overall financial condition and any other factors deemed relevant by our board of directors.

The following table sets forth our cash, cash equivalents and investments and our total capitalization as of March 31, 2011:

The pro forma and pro forma, as adjusted, information below is illustrative only and our capitalization following the completion of this offering will be adjusted based on the actual initial public offering price and other terms of this offering determined at pricing. You should read this table together with “Management’s discussion and analysis of financial condition and results of operations” and our consolidated financial statements and the accompanying notes appearing elsewhere in this prospectus.

Each $1.00 increase (decrease) in the assumed initial public offering price of $ per share (the mid-point of the price range set forth on the cover page of this prospectus) would increase (decrease) our pro forma, as adjusted cash, cash equivalents and investments, additional paid-in capital and stockholders’ equity by approximately $ million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The number of shares of common stock shown as issued and outstanding in the table set forth above is based on the number of shares of our common stock outstanding as of March 31, 2011 and excludes:

If you invest in our common stock, your interest will be diluted to the extent of the difference between the public offering price per share of our common stock and the pro forma, as adjusted net tangible book value per share of our common stock after this offering.

Our pro forma net tangible book value at March 31, 2011 was $ million, or $ per share of common stock. Pro forma net tangible book value per share represents total tangible assets less total liabilities (which includes the reclassification of preferred stock warrant liability into additional paid-in capital upon the conversion of outstanding preferred stock warrants into shares of common stock), divided by the number of outstanding shares of common stock on March 31, 2011, after giving effect to the conversion of all of our outstanding preferred stock, preferred stock warrants and common stock warrants into shares of our common stock in connection with the completion of this offering.

Our pro forma, as adjusted net tangible book value at March 31, 2011, after giving effect to the sale by us of shares of common stock in this offering at an assumed initial public offering price of $ per share (the mid-point of the price range set forth on the cover page of this prospectus) and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us, would have been approximately $ million, or $ per share. This represents an immediate increase in pro forma, as adjusted net tangible book value of $ per share to existing stockholders and an immediate dilution of $ per share to new investors purchasing shares of our common stock in this offering at the assumed initial public offering price of $ per share (the mid-point of the price range set forth on the cover page of this prospectus), subject to adjustment to reflect the actual offering price. The following table illustrates this per share dilution:

A $1.00 increase (decrease) in the assumed initial public offering price of $ per share (the mid-point of the price range set forth on the cover page of this prospectus) would increase (decrease) our pro forma, as adjusted net tangible book value by $ million, the pro forma, as adjusted net tangible book value per share by $ per share and the dilution in the pro forma net tangible book value to new investors in this offering by $ per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The following table shows, as of March 31, 2011, the number of shares of common stock purchased from us, the total consideration paid to us and the average price paid per share by existing stockholders and by new investors purchasing common stock in this offering at an assumed initial public offering price of $ per share (the mid-point of the price range set forth on the cover page of this prospectus), before deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The table above, and the information below, assume that our existing stockholders do not purchase any shares in this offering.

A $1.00 increase (decrease) in the assumed initial public offering price of $ per share (the mid-point of the price range set forth on the cover page of this prospectus) would increase (decrease) total consideration paid by new investors, total consideration paid by all stockholders and the average price per share paid by all stockholders by $ million, $ million and $ , respectively, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and before deducting the underwriting discount and estimated offering expenses payable by us.

The discussion and tables in this section regarding dilution are based on shares of common stock issued and outstanding as of March 31, 2011, which assumes the conversion of all of our preferred stock, preferred stock warrants and common stock warrants into an aggregate of shares of our common stock in connection with the completion of this offering, and excludes:

If the underwriters exercise their option to purchase additional shares in full, the following will occur:

To the extent that outstanding options are exercised, you will experience further dilution. If all of our outstanding options were exercised, our pro forma net tangible book value as of March 31, 2011 would have been $ million, or $ per share, and the pro forma, as adjusted net tangible book value after this offering would have been $ million, or $ per share, causing dilution to new investors of $ per share.

In addition, we may choose to raise additional capital due to market conditions or strategic considerations even if we believe we have sufficient funds for our current or future operating plans. To the extent that we raise additional capital through the sale of equity or convertible debt securities, the issuance of these securities could result in further dilution to our stockholders.

The following selected historical consolidated financial data should be read together with our consolidated financial statements and the accompanying notes appearing elsewhere in this prospectus and “Management’s discussion and analysis of financial condition and results of operations.” The selected historical consolidated financial data in this section is not intended to replace our historical consolidated financial statements and the accompanying notes. Our historical results are not necessarily indicative of our future results.

We derived the consolidated statements of operations data for 2008, 2009 and 2010 and the consolidated balance sheet data as of December 31, 2009 and 2010 from our audited consolidated financial statements appearing elsewhere in this prospectus. The consolidated statements of operations data for 2006 and 2007 and the consolidated balance sheet data as of December 31, 2006, 2007 and 2008 have been derived from our audited consolidated financial statements not included in this prospectus. The consolidated statements of operations data for the three months ended March 31, 2010 and 2011 and the consolidated balance sheet data as of March 31, 2011 are derived from our unaudited interim consolidated financial statements appearing elsewhere in this prospectus. The unaudited interim financial statements have been prepared on the same basis as the audited annual consolidated financial statements and, in the opinion of management, reflect all adjustments, which include only normal recurring adjustments, necessary to state fairly our financial position as of March 31, 2011 and results of operations for the three months ended March 31, 2010 and 2011. Operating results for the three months ended March 31, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. The data should be read in conjunction with the consolidated financial statements, accompanying notes, and other financial information included herein.

Management’s discussion and analysis of financial condition and results of operations

The following discussion and analysis of our business, financial condition and results of operations should be read in conjunction with our consolidated financial statements and accompanying notes that appear elsewhere in this prospectus. In addition to historical consolidated financial information, the following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed below. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this prospectus, particularly in “Risk factors.”

Our technology allows us to economically and sustainably create natural gas from current wells, thereby utilizing and extending the life of existing natural gas infrastructure, and minimizing our need for new drilling. We produce this newly created natural gas from existing wells and deliver it to the natural gas market via existing pipelines. Unlike the traditional E&P industry’s extraction methods in which production peaks and then steeply declines as stored hydrocarbons are depleted, we believe, based on lab and field results, that our Restoration Process economically and sustainably creates low-cost clean energy for many years. We believe our technology competes favorably with the traditional “hunter/gatherer” style of natural gas development (find, drill, produce, then abandon) by allowing a “farming” style of natural gas creation (restore, feed, grow, then harvest), which continually produces a new crop of natural gas.

Management’s discussion and analysis of financial condition and results of operations

Our operations are initially focused in the PRB where we currently own and operate more than 1,350 wells. We anticipate growing our business primarily through acquiring natural gas properties in the PRB and other basins in the United States and abroad, applying our Restoration Process to these properties to create new sustainable sources of natural gas, and producing and selling this natural gas to existing markets. In the future, we may expand our efforts to include oil and organic-rich shales.

Acquisition of natural gas properties: Between 2007 and 2010, we acquired over 1,350 wells and associated natural gas gathering assets in the PRB to support the development and commercialization of our technology. In late 2007, we acquired approximately 100 wells in a transaction that included a total cash payment of approximately $0.6 million, plus the assumption of an asset retirement obligation of approximately $0.4 million. In June 2008, we acquired approximately 530 wells in a transaction that included a total cash payment of $9.6 million, plus the assumption of approximately $3.2 million in liabilities, consisting of an asset retirement obligation of approximately $2.5 million and an obligation to issue 200,000 shares of common stock in the future. In March and April 2010, we acquired approximately 730 wells along with a natural gas gathering system and related assets in a transaction that included a total cash payment of approximately $2.3 million, plus the assumption of approximately $2.3 million in asset retirement obligations, and the issuance of 25,000 shares of common stock. The total purchase price for an acquisition reflects several factors, including estimated future natural gas production and cash flows from the properties prior to the deployment of our Restoration Process, the suitability of the wells for the implementation of our technology, and expected natural gas prices.

Natural gas pricing: Our revenues depend on natural gas prices. During periods of low natural gas prices, such as the spring, summer and fall of 2009, we elected to shut-in natural gas production from many of our wells and to defer such production to a future period of higher prices. Given our primary focus on the PRB, we expect the majority of our production to be sold directly into the main transportation infrastructure of the Colorado Interstate Gas Company, or CIG, and to be priced at either the CIG or Cheyenne Hub index. Due to the physical distance of the PRB from the Henry Hub, we expect our pricing to reflect a discount differential to Henry Hub prices, consistent with historical trends. From January 1, 2008 through March 31, 2011, prices in the PRB have fluctuated from a high of over $10.00 per MMBtu in July 2008 to a low of under $2.00 per MMBtu in September 2009, with such fluctuations largely attributable to changes in demand resulting from general economic conditions and seasonality factors. We periodically use derivative financial instruments to achieve a more predictable cash flow from our natural gas production by reducing our exposure to natural gas price fluctuations. We entered into physical commodity contracts with our natural gas purchaser for the sale of 300 MMBtu per day of natural gas from April 2008 through October 2008 at a minimum price of $7.74 per MMBtu, and for the sale of 2,000 MMBtu per day of natural gas from July 2008 through June 2009 at a price of $9.38 per MMBtu. We also entered into a physical fixed-price commodity contract with our natural gas purchaser for the sale of 400 MMBtu per day of natural gas through March 2008 at a price of $5.28 per MMBtu. Our average price per Mcf of natural gas produced and sold for the three years ended December 31, 2010 and the three months ended March 31, 2010 and 2011 are summarized below, before and after the impact of our derivative instruments in place during 2008 and 2009. We had no derivative instruments in place in 2010 and 2011 so there was no adjustment in our natural gas price.

Management’s discussion and analysis of financial condition and results of operations

Variable operation during development: During the periods presented, we have been developing our technology and have not been operating on a commercial scale. In addition to natural gas pricing fluctuations, our operating revenues and expenses were significantly impacted by changes in the number of wells producing over this time, as our operations were focused initially on testing and developing the technology rather than maximizing revenue from the wells.

Our natural gas production has fluctuated significantly from 2008 through March 31, 2011 due to seasonality, a decline in natural gas prices, the timing of well acquisitions and certain regulatory matters that impacted our ability to perform our Restoration Process. Adverse weather conditions can also negatively affect our production rates. Until March 2010, we performed our Restoration Process on over 275 of our wells in the PRB under a pilot program regulated by the WOGCC. As we moved towards commercialization of our technology, new legislation and regulations were required to permit commercial-scale circulation of our nutrient formulations in the PRB. This legislation was passed in February 2011. Rules implementing this legislation are expected to be finalized by the fall of 2011, and we expect to obtain required regulatory approvals in that time frame. In order to conserve water pending the completion of this process, we elected in April 2010 to shut-in a majority of the wells that we had previously restored. Since April 2010, our production has generally been limited to those wells that are generating natural gas at pressures sufficient to allow for production without pumping water, unlike traditional coalbed methane production.

We also produced a limited number of wells acquired in 2010 during the period from July 2010 through November 2010 to prepare such wells for future restoration treatment. Since the majority of the wells we have acquired were uneconomic at the date of acquisition using traditional coalbed methane practices, other than those acquired in 2008 during a period of significantly higher natural gas prices, we typically do not produce such wells until after they have been treated with our Restoration Process and new methanogenic natural gas production has begun. Thus, there is not a direct correlation between the number of wells owned and those producing.

The following table summarizes the average number of wells producing from January 1, 2008 through March 31, 2011 compared to the number of wells owned by us during the same period:

Management’s discussion and analysis of financial condition and results of operations

The following table sets forth our natural gas sales and production volumes, along with average production costs per Mcf based on these volumes for the periods presented:

We record revenue from the sale of natural gas when delivery to the customer has occurred and title has transferred. Our natural gas revenues are directly related to the quantity of natural gas produced and sold on a daily basis and the natural gas prices in effect on such dates, subject to any commodity price hedging contracts we may have in place. Our natural gas sales are currently to one purchaser, United Energy Trading, LLC. We believe that, due to the nature of our product, we are not dependent upon this customer. Natural gas revenues are paid to us approximately 25 days after the end of a given month. Collectability is based on the financial wherewithal of such purchaser and all sales to this purchaser have been collected. Since 2008, all of our revenues have been from natural gas sales. We also received revenue in 2006 and 2007 for management services related to our technology under a contractual arrangement with an unrelated third party. Revenue was recorded on management services in the month that the related services were provided, as no significant remaining obligations or acceptance provisions existed.

Our research and development expenses consist of costs directly related to developing nutrient formulations, sampling wells, the testing and analysis of such samples, and improving the results of our technology in both the lab and field. Research and development expenses include personnel costs (including stock-based compensation), fees paid to consultants and related contract research, lab facility costs, supplies, travel and related costs associated with sampling, testing and field demonstration projects where we do not own the wells, and intellectual property and patent costs. Cash received from funded research and development studies in which no obligation exists to repay such amounts is netted against the expense. For the years ended December 31, 2008, 2009 and 2010, the amounts netted against research and development expenses were approximately $100,000, $68,000, and $87,500, respectively. No amounts were netted against research and development expenses during the quarter ended March 31, 2011.

Management’s discussion and analysis of financial condition and results of operations

Our lease operating expenses consist of the costs associated with producing natural gas from our properties, and include personnel and related costs of our employees responsible for the operation of our wells, annual surface use agreement payments, shut-in payments and minimum royalties connected to our leases, electricity costs, facility costs associated with our field office, operators insurance, regulatory compliance, consulting, roustabout services and contract labor. Lease operating expenses do not include lease or well acquisition costs, or finding and creation costs related to the application of our Restoration Process, all of which are capitalized. We expect these costs, on a per Mcf basis, to decline significantly as we increase the scale of our operations.

Our gathering and transportation expenses consist of fees and costs to collect and transport our natural gas from the well head to the sales point at the pipeline hub. These costs are comprised of the cost of treating and compressing the natural gas to a composition and pressure adequate to meet pipeline requirements and include the cost of natural gas used to operate the equipment, including pumps and compressors. To date, most of these gathering and transportation expenses have been costs paid to third parties for operation of their gathering systems and transportation lines. We purchased a small gathering system in the PRB in 2010, and we anticipate that once we begin to operate this system in the second half of 2011, we will experience a significant reduction in our gathering and transportation expense per Mcf of natural gas produced.

Our general and administrative expenses consist of personnel costs (including stock-based compensation), hiring and training costs, consulting and service provider expenses, legal costs, corporate insurance costs, facility and occupancy-related costs, general office costs, and travel and relocation expenses. Overhead fees received related to operating natural gas properties for other working interest owners are netted against general and administrative expenses. After completion of this offering, we anticipate increases in general and administrative expenses as we incur additional compliance costs as a public company. These increases will likely include increased costs for insurance, costs related to the hiring of additional personnel and payments to outside consultants, lawyers and accountants. We also expect to incur significant costs to comply with the corporate governance, internal controls and similar requirements applicable to public companies.

The preparation of our consolidated financial statements requires us to make estimates, assumptions and judgments 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 applicable periods. Management bases its estimates, assumptions and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances. Different assumptions and judgments would change the estimates used in the preparation of our consolidated financial statements, which, in turn, could change the results from those reported. Our management evaluates its estimates, assumptions and judgments on an ongoing basis. While our significant accounting policies are more fully described in Note 1 to our consolidated financial statements included elsewhere in this prospectus, we believe that the following accounting policies are the most critical to aid you in fully understanding and evaluating our reported financial results and reflect the more significant judgments and estimates that we use in the preparation of our consolidated financial statements.

Management’s discussion and analysis of financial condition and results of operations

Effective January 1, 2010, we adopted the requirements of Financial Accounting Standards Board, or FASB, Accounting Standards Codification, or ASC, 932, Extractive Activities- Oil and Gas, and are accounting for our natural gas creation and development activities under the successful efforts method. Under this method, all natural gas property acquisition costs (including lease acquisition costs) and the costs directly associated with our Restoration Process on our natural gas properties are capitalized when incurred. We treat our Restoration Process costs similarly to development costs (per ASC 932-360-25-12 to 16) or enhanced recovery costs. Geological, geophysical, and general maintenance and repairs not associated with the Restoration Process are charged to expense, while renewals and betterments are capitalized to the appropriate property and equipment accounts. All of our natural gas properties are currently located in the State of Wyoming, although we have performed our Restoration Process on wells in other basins throughout the United States, and such costs are charged to research and development expense unless we have an economic interest in such wells.

Depreciation and depletion of producing natural gas properties is recorded at the field level, based on the units-of-production method using total proved reserves. These proved reserves were estimated by our internal reservoir engineer and include the benefits of our Restoration Process on a limited number of wells. All capitalized natural gas property costs are depleted using total proved developed reserves. See “Business—Oil and Natural Gas Reserves.”

Beginning in 2010, we believed that the performance of our field demonstration projects had provided the necessary positive results to conclude that our Restoration Process could meet the definition of “reliable technology” under ASC 932. Our proved reserves include the impact of our Restoration Process on a limited number of wells which have previously been treated. Prior to 2010, we had not adopted the requirements of ASC 932 as our natural gas properties were non-traditional coalbed methane resources. Additionally, due to the nature of our Restoration Process, which involves the continuous creation and production of natural gas in real-time, we believed the unit-of-production method did not provide the most accurate or reasonable means of calculating depreciation and depletion expense on our natural gas properties. Since we are unable to differentiate natural gas production from existing reserves at the time of an acquisition compared to newly created restoration natural gas, the use of units-of-production depletion accounting, without inclusion of all reserves generated by our Restoration Process, could result in an inappropriate acceleration of expense.

To more accurately depreciate or deplete capitalized costs over the life of the producing properties, a segmented approach was taken. Natural gas property acquisition costs directly associated with proved developed producing reserve value were depleted on a declining balance method using the estimated future net cash flows over the economic life of the properties attributable to the production and reserves in place at the time of the acquisition without taking into consideration our Restoration Process.

The remaining natural gas property acquisition costs not associated with proved developed producing reserve value, including costs related to wellbores and wellhead equipment necessary for the future development of the natural gas properties through our Restoration Process, were depreciated using the straight-line method over a ten year estimated life of the properties. Although management currently believes the useful life of such assets will extend beyond the 10-year estimate, the application of our Restoration Process remains in the early stages of development and definitive data to support a longer period is not available. We believe that we can successfully perform our Restoration Process on a well at least twice, with each application resulting in the economic production of natural gas for four to five years. Based on historical data related to our Restoration Process, in 2009 we depleted capitalized restoration costs using a 54-month period, while prior to 2009 restoration costs were depleted using a

Management’s discussion and analysis of financial condition and results of operations

three-year period based on a shorter history for results from testing. Taken into consideration in the calculation of depletion and depreciation were estimated future dismantlement and abandonment costs and estimated salvage values.

We account for our asset retirement obligations, or ARO, in accordance with ASC 410, Asset Retirement and Environmental Obligations. The estimated fair value of the future costs associated with dismantlement and abandonment of natural gas properties and natural gas gathering assets is generally recorded upon acquisition of a well. The estimated costs are discounted to present values using a risk-adjusted rate over the estimated economic life of the natural gas properties or natural gas gathering assets. Such costs are capitalized as part of the related asset. The associated liability is classified in long-term liabilities. The liability is periodically adjusted to reflect: (1) new liabilities incurred; (2) liabilities settled during the period; (3) accretion expense; and (4) revisions to estimated future dismantlement and abandonment costs.

Since the adoption of our equity incentive plan in 2007 we have recorded all share based payment expenses in accordance with the provisions ASC 718, Compensation—Stock Compensation.

Prior to our conversion from a limited liability company to a corporation in April 2007, we had not granted stock options but had issued profit unit interests to our employees and members of our board of directors. The terms and conditions of the profit unit interests resembled those of a stock-appreciation rights program and thus were accounted for as such, with compensation expense recognized for the incremental vested appreciation of such interests at each respective reporting period. Upon our conversion to a corporation, these interests were converted into common stock, thus no further expense was recorded.

The following table summarizes the stock options granted from January 1, 2008 through March 31, 2011 with their exercise prices, the fair value of the underlying common stock per share, if any:

As required by ASC 718, we have computed the estimated fair value of options granted using the Black-Scholes option pricing model and recognize the expense over the requisite service period of the awards on a straight-line basis. In order to calculate the fair value of the options, certain assumptions are made regarding components of the model, including risk-free interest rate, volatility, expected dividend yield, and expected option life. Changes to the assumptions could cause significant adjustment to the valuation. We estimated a volatility factor based on an average of volatilities for public companies with similar characteristics and growth potential. We applied the simplified method to determine the expected term of the grant and have estimated the future annual forfeiture rate at 5% after evaluating historical and

Management’s discussion and analysis of financial condition and results of operations

expected employee turnover. We do not anticipate issuing a dividend thus a 0% dividend yield was estimated. Accordingly, we have computed the fair value of all options granted during the years ended December 31, 2008, 2009 and 2010, using the following assumptions:

We periodically use derivative financial instruments to achieve a more predictable cash flow from our natural gas production by reducing our exposure to natural gas price fluctuations. In 2008, we entered into physical commodity contracts with our natural gas purchaser for the sale of 300 MMBtu per day of natural gas from April 2008 through October 2008 at a minimum price of $7.74 per MMBtu, and for the sale of 2,000 MMBtu per day of natural gas from July 2008 through June 2009 at a price of $9.38 per MMBtu. We also entered into a physical fixed-price commodity contract with our natural gas purchaser for the sale of 400 MMBtu per day of natural gas through March 2008 at a price of $5.28 per MMBtu. Our natural gas derivative financial instruments are accounted for in accordance with ASC 815, Derivatives and Hedging. We have elected the normal purchase and sale exception permitted under ASC 815 and accordingly are not required to apply the provisions to the fixed-price gas contracts. As a result, no asset or liability has been recorded for the fair value of these contracts in the accompanying consolidated balance sheets. As of December 31, 2009 and 2010, no derivative contracts were in place.

We assesses the recoverability of our natural gas properties when circumstances suggest there is a need for such review in accordance with ASC 360, Property, Plant, and Equipment. We estimate the expected undiscounted future cash flows of our natural gas properties, to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the natural gas properties to fair value. We performed an impairment analysis of our natural gas properties for each of the years ended December 31, 2008, 2009 and 2010 and in each case future undiscounted cash flows exceeded the carrying amount of the properties.

We account for income taxes under the asset and liability method. Under this method, deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis using enacted tax rates in effect for the year in which the differences are expected to affect taxable income. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts expected to be ultimately realized. We have incurred operating losses since inception. As of December 31, 2010, we had federal and state net operating loss carryforwards of approximately $45.8 million which may be used to offset future taxable income. We also had federal research and development tax credit carryforwards of $2.0 million. These carryforwards expire at various times through 2030. We have established a valuation allowance in the full amount of our net tax asset since we have concluded that it is not more likely than not that we will be able to utilize these assets based on our historical losses.

Management’s discussion and analysis of financial condition and results of operations

Our convertible preferred stock is classified outside of stockholders’ equity due to the liquidation rights of the holders. The holders of our convertible preferred stock currently control the vote of our board of directors through their appointed representatives. As a result the holders can force a disposition or transaction that would trigger liquidation. Since redemption of the convertible preferred stock through liquidation is outside our control, all shares of convertible preferred stock have been presented outside of permanent equity on the consolidated balance sheets at their issuance day fair value.

The following table presents selected items from our consolidated statements of operations for the periods presented, showing period-over-period changes, in thousands:

Revenue. The decrease in revenue of approximately $0.6 million, or 70%, was primarily due to an approximately 64% decline in natural gas production related to our decision to shut-in production from the majority of our wells to conserve water pending the outcome of the Wyoming regulatory matters discussed above. See “—Significant factors and trends affecting our results of operations—Variable operation during development.” Since December 2010, natural gas production has been limited to those wells that are generating natural gas at pressures sufficient to allow for production without pumping water, unlike with traditional coalbed methane production. These same wells produced significantly higher quantities of natural gas in 2010, when we were able to implement our Restoration Process in the field. In addition, natural gas prices declined approximately 4%, from an average price of $3.83 per Mcf in 2010 to $3.68 per Mcf in 2011.

Research and development expense. The decrease in research and development expenses of approximately $0.6 million, or 30%, was primarily related to reduced costs of approximately $0.5 million resulting from the reduction in personnel in November 2010 and reduced field activities pending the outcome of our Wyoming regulatory matters.

Management’s discussion and analysis of financial condition and results of operations

Lease operating expense. Lease operating expenses decreased by approximately $0.4 million, or 36%, which is consistent with the significant decrease in the number of wells producing and the number of field employees between the periods due to the reduction in field personnel in November 2010 as a result of legislative and regulatory matters. Certain fixed costs, such as surface use agreement payments and shut-in fees, continue to be paid even when a well is not producing.

Gathering and transportation expense. The decrease in gathering and transportation expenses of approximately $0.2 million, or 52%, was primarily due to the approximately 64% reduction in natural gas production, partially offset by increased gathering costs per Mcf as we agreed to pay higher short-term fees to our third party gas gatherer to provide more flexibility to connect a portion of our producing wells to our own gathering system.

Production taxes. The decrease in production taxes of approximately $49,000, or 68%, is directly related to the approximately 70% decrease in revenues discussed above, as production taxes are calculated based on a percentage of natural gas sales, excluding hedging gains and losses.

General and administrative expense. The increase in general and administrative expense of $0.4 million, or 31%, was primarily related to increased personnel costs (including stock-based compensation) associated with the hiring of additional senior management, including the hiring of a new Chief Executive Officer in October 2010, Corporate Counsel in January 2011, and Chief Development Officer in February 2011. General and administrative expense included stock-based compensation expense of approximately $68,000 and approximately $0.3 million in 2010 and 2011, respectively.

Depreciation, depletion and amortization. The decrease in depreciation, depletion and amortization of approximately $0.1 million, or 24%, was primarily related to lower depletion of our natural gas producing assets due to the approximately 64% lower production volumes in the first quarter of 2011 compared to 2010 as depletion of these assets under the units-of-production method varies with production, while the straight line method applied to certain other assets remained constant.

The following table presents selected items from our consolidated statements of operations for the periods presented, showing period-over-period changes, in thousands:

Management’s discussion and analysis of financial condition and results of operations

Revenue. The decrease in revenue of approximately $1.4 million, or 37%, was primarily due to an approximately 51% decrease in the average natural gas price received, from $7.86 per Mcf in 2009 to $3.83 per Mcf in 2010, partially offset by an approximately 30% increase in production. The natural gas price in 2009 includes the impact of our natural gas hedging contract, which resulted in additional natural gas revenue of approximately $2.4 million. However without taking into consideration our hedging contract, average realized natural gas prices in 2009 would have been $2.94 per Mcf instead of $7.86 per Mcf, and would have increased by 30% year-over-year. The increase in natural gas production is due to reduced production in 2009 as we shut-in most of our wells during the summer and fall of 2009, subsequent to the expiration of our hedging contract on June 30, 2009, due to low natural gas prices. The wells were turned back on to production in November and December 2009 as natural gas prices recovered, and production was strong during the first quarter of 2010, especially from wells restored in 2008 and early 2009.

Research and development expense. The increase in research and development expenses of $0.9 million, or 14%, was primarily related to increased personnel, consulting and lab costs associated with enhancing our DNA sequencing and Bioinformatics capabilities in our lab facilities, resulting in the creation of a library of information on methanogenic processes and agents. Additionally, our spending in 2010 increased primarily for costs to support increased field testing on wells outside of the PRB, including wells in the Black Warrior Basin of Alabama and the Uinta Basin in Utah.

Lease operating expense. Lease operating expenses increased by approximately $1.1 million, or 36%, in 2010 consistent with the increase in costs associated with the acquisition of approximately 730 wells in March 2010. Although none of the wells acquired were producing natural gas or water, and most had been shut-in for several months prior to our acquisition, the fixed costs for items such as surface use agreement payments and shut-in or minimum royalties related to the natural gas leases, and the start-up costs spent to provide electricity to the wells so that some could be produced and others tested and sampled pending future restoration activity, caused lease operating expenses to increase during 2010.

Gathering and transportation expense. The increase in gathering and transportation expenses of approximately $0.5 million, or 57.0%, was primarily due to the approximately 30% increase in natural gas production in 2010 and the approximately 21% increase in gathering and transportation expense per Mcf of natural gas produced. The increase in cost per Mcf of natural gas produced was related to our resuming operations in certain areas where we paid the third-party gathering company relatively higher fees compared to our average producing properties. In addition, we incurred increased compression costs as overall production declined in the PRB when lower natural gas prices led other operators to slow their drilling activities, causing producing properties to be allocated higher costs due to the resulting inefficiency of the compressors.

Production taxes. The increase in production taxes of approximately $76,000, or 58%, was directly related to the approximately 30% increase in natural gas production and the approximately 30% year-over-year increase in the average price per Mcf of natural gas produced, before taking into consideration derivative instruments.

General and administrative expense. The increase in general and administrative expense of approximately $1.5 million, or 33%, was related to several factors, including increased personnel, hiring and stock-based compensation costs associated with the addition of a new Chief Executive Officer, severance payments to employees laid off in November 2010 as we were focused on reducing expenditures pending the passage of legislation in Wyoming, increased legal fees associated with such legislation and other regulatory issues, and increased land and accounting consulting fees related to the acquisition of approximately 730 wells in March 2010.

Management’s discussion and analysis of financial condition and results of operations

Depreciation, depletion and amortization. The decrease in depreciation, depletion and amortization of approximately $1.2 million, or 32%, is primarily related to our adoption of ASC 932, Extractive Activities- Oil and Gas, effective January 1, 2010.

The following table presents selected items from our consolidated statements of operations for the periods presented, showing period-over-period changes, in thousands:

Revenue. The decrease in revenue of approximately $1.5 million, or 28%, was primarily due to an approximately 38% decline in natural gas production for 2009 as we elected to shut-in a majority of our wells during the summer and fall of 2009, subsequent to the expiration of the natural gas hedging contract in place through June 30, 2009, due to low natural gas prices. This decline in production was partially offset by higher realized natural gas prices in 2009, primarily due to the natural gas hedging contract discussed above, as average natural gas prices in 2009 were approximately 15% higher than 2008. However, without taking into consideration the natural gas hedging contract, average realized prices would have been $2.94 per Mcf instead of $7.86 per Mcf and would have declined by approximately 47% from 2008.

Research and development expense. The increase in research and development expense of approximately $1.6 million, or 31%, was primarily related to an increased focus on lab research 2009 and higher costs associated with field demonstration projects outside of the PRB, including the Black Warrior Basin in Alabama, the San Juan Basin in New Mexico and the Uinta Basin in Utah. As part of our increased focus on lab research and development, we increased our staff during the year and in September 2009 hired our current Chief Technology Officer. Higher personnel costs, including stock-based compensation and hiring costs, represent the majority of the increase, while demonstration projects outside of the PRB make up the remainder of the increase.

Lease operating expense. Total lease operating expenses did not significantly fluctuate between 2008 and 2009. This was the result of two significant but offsetting factors. As previously noted, natural gas production decreased by approximately 38% on a year-over-year basis, causing the related variable costs to decline. Offsetting this was a significant increase in fixed operating costs attributable to the wells acquired in June 2008, and which were in place for the full year 2009.

Management’s discussion and analysis of financial condition and results of operations

Gathering and transportation expense. The increase in gathering and transportation expenses of approximately $0.1 million, or 19%, was primarily due to the increase in fuel usage as a percentage of total production when lower volumes are produced and greater compression is required, which was partially offset by the approximately 38% reduction in production volumes.

Production taxes. The decrease in production taxes of approximately $0.3 million, or 69%, is directly related to the 38% reduction in natural gas production previously discussed and the approximate 47% year-over-year decrease in average price per Mcf of natural gas produced without taking into consideration natural gas hedging arrangements.

General and administrative expense. The increase in general and administrative expense of approximately $1.8 million, or 68%, primarily related to increased personnel costs attributable a full year of operating properties acquired in 2008 and the substantial growth plans following equity financing raised at the end of 2008. Prior to that acquisition, we were only operating approximately 100 wells and did not need a sizeable land, accounting or administrative staff. A significant number of employees were hired during the second half of 2008 and remained employed throughout all of 2009. In addition, legal costs increased by approximately $0.4 million related to regulatory and acquisition work during the year.

Depreciation, depletion and amortization. The increase in depreciation, depletion and amortization of approximately $0.6 million, or 17%, was primarily related to the acquisition of additional wells in 2008, and the resulting full year of depreciation realized on these assets in 2009 as compared to the half year of depreciation recognized in 2008.

Our primary sources of liquidity to date have been sales of equity securities to our investors, borrowings under a bank note, revenues generated from the sale of natural gas produced and the performance of field studies and site management for unrelated third parties in 2006 and 2007. Our capital has primarily been used to acquire assets on which our Restoration Process can be deployed and to perform the research and development activities necessary to make deployment of our Restoration Process feasible. In addition to the initial funding by our founders, we have successfully concluded a series of venture capital and private equity offerings between 2006 and 2008 totaling approximately $99 million. Our financial partners include Kleiner Perkins Caufield & Byers, One Equity Partners, Oxford Bioscience Partners and BASF Venture Capital.

As of March 31, 2011, our cash and cash equivalents totaled approximately $27.2 million. In addition, we have approximately $5.6 million of investments in commercial paper with maturities of less than twelve months. Based on our current level of operations and anticipated growth, we believe that the anticipated net proceeds from this offering, our existing cash, cash equivalents, investments, and subsequent cash flows from operations will provide adequate funds for ongoing operations, planned capital expenditures and working capital requirements for at least the next twelve months. Successful deployment of our Restoration Process at scale, and ultimately, the attainment of profitable operations are dependent upon future events, including acquisition of additional natural gas properties at acceptable prices, development of appropriate government rules and regulations that allow for the timely deployment of our Restoration Process, obtaining required regulatory approvals and natural gas pricing within our expected range, among others. If our revenues and cash flows in the future are less than anticipated, we may reduce or delay our planned capital expenditures until conditions become more favorable to our continued expansion of ownership of wells.

Management’s discussion and analysis of financial condition and results of operations

The following table sets forth the major sources and uses of cash for each of the periods set forth below:

Our primary uses for cash from operating activities are personnel-related expenses, research and development-related expenses, the operating costs of our wells, including lease operating expenses, gathering and transportation expenses and production taxes, other general and administrative expenses such as facility costs, travel, legal and other consulting fees, and state and federal bonding amounts related to plugging and abandonment costs associated with our natural gas properties.

Cash used in operating activities of approximately $3.6 million during the three months ended March 31, 2011 reflected our net loss of approximately $4.3 million offset by non-cash charges totaling approximately $0.9 million and further uses of cash as a result of changes in operating assets and liabilities of approximately $0.3 million. Non-cash charges included depreciation, depletion and amortization of approximately $0.4 million, and stock-based compensation of approximately $0.5 million. The net use of cash from our operating assets and liabilities of approximately $0.3 million reflected fluctuations in receivables and payables and other changes in the ordinary course of our business.

Cash used in operating activities of approximately $19.2 million in 2010 reflected our net loss of approximately $19.7 million, offset by non-cash charges totaling approximately $3.5 million and further uses of cash as a result of changes in operating assets and liabilities of approximately $3.1 million. Non-cash charges included depreciation, depletion and amortization of approximately $2.6 million, and stock-based compensation of approximately $0.8 million. The net use of cash from our operating assets and liabilities of approximately $3.1 million primarily reflected approximately $2.4 million deposits for bonds required by Wyoming regulatory agencies in relation to our acquisition of additional wells during 2010.

Cash used in operating activities of approximately $10.9 million in 2009 reflected our net loss of approximately $15.4 million, offset by non-cash charges totaling approximately $4.6 million. Non-cash charges included depreciation, depletion and amortization of approximately $3.9 million, stock-based compensation of approximately $0.6 million, and loss from changes in fair value of warrant liabilities of approximately $45,000.

Cash used in operating activities of approximately $5.9 million in 2008 reflected our net loss of approximately $9.8 million, offset by non-cash charges totaling approximately $4.1 million and further uses of cash as a result of changes in our operating assets and liabilities of approximately $0.2 million. Non-cash charges included depreciation, depletion and amortization of approximately $3.3 million, and stock-based compensation of approximately $0.8 million. The net use of cash from our operating assets and liabilities of approximately $0.2 million reflected fluctuations in receivables and payables and other changes in the ordinary course of business.

Management’s discussion and analysis of financial condition and results of operations

Our investing activities consist primarily of the acquisition of natural gas properties, the deployment of our Restoration Process on our current and acquired wells, the purchase of research and development and field equipment, and purchases and maturities of investments.

During the three months ended March 31, 2011, cash provided by maturities of investments of approximately $2.4 million was partially offset by cash used for purchases of equipment of approximately $0.3 million.

In 2010, cash used in investing activities was primarily related to approximately $8.0 million of purchases of short-term investments, approximately $2.7 million for purchases of equipment in our lab facilities and related to restoration activities on our properties, and approximately $2.3 million in cash payments to acquire additional wells and a natural gas gathering system.

In 2009, cash used in investing activities was related to approximately $2.3 million for purchase of equipment in our lab facilities and approximately $0.3 million related to restoration activities on our properties.

In 2008, cash used in investing activities was primarily related to approximately $9.6 million in cash payments to acquire additional operating interests in wells and approximately $3.2 million for purchases of equipment in our lab facilities and related to restoration activities on our properties, partially offset by net maturities of investments of approximately $8.0 million.

During the three months ended March 31, 2011, cash used by financing activities was approximately $0.1 million related to the repayment of approximately $0.3 million of principal under our bank loan, partially offset by net proceeds of approximately $0.1 million from the exercise of common stock options.

In 2010, cash used by financing activities was approximately $1.1 million, due to repayment of principal under our bank loan.

In 2009, cash used by financing activities was approximately $0.6 million, primarily due to repayment of approximately $0.6 million of principal under our bank loan.

In 2008, cash provided by financing activities was approximately $84.1 million, primarily due to net proceeds of approximately $75.9 million from the sale of Series C preferred stock, approximately $5.5 million from the sale of Series B preferred stock and approximately $3.0 million borrowed under our bank loan, partially offset by approximately $0.2 million of stock issuance costs.

On April 30, 2008, we entered into a loan and security agreement with Silicon Valley Bank to finance equipment purchases and provide working capital. The available amount under the agreement was $3.0 million. Amounts outstanding are payable in 36 consecutive equal monthly installments of principal plus accrued interest, beginning May 2009 and continuing through April 2012. The outstanding principal amount accrued interest at a floating rate through April 30, 2009, and was then fixed at 4% per annum. Advances under the agreement are secured by all of our assets, other than intellectual property, natural gas reserves and the associated wells and net cash flow from the production of such wells, natural gas gathering assets, and our equity interests in Patriot Energy Resources LLC and Patriot Energy Gathering

Management’s discussion and analysis of financial condition and results of operations

LLC. The agreement does not contain financial ratio covenants, but does impose certain affirmative and negative covenants. We are currently in compliance with all such covenants. As of March 31, 2011, approximately $1.1 million was outstanding under this agreement, net of discount.

The following summarizes the future commitments arising from our contractual obligations at December 31, 2010:

The table above reflects only payment obligations that are fixed and determinable. The above amounts exclude potential payments to be made under our license and other agreements that are based on the achievement of future milestones or royalties on product sales.

On June 2, 2011, we settled a dispute with the company from whom we had purchased natural gas properties and related assets in 2008. Pursuant to such settlement, we waived our claim to payments resulting from a dispute over items in the purchase and sale agreement and they waived their claims to 200,000 shares of our common stock.

We did not have during the periods presented, and we do not currently have, any relationships with unconsolidated entities, such as entities often referred to as structured finance or special purpose entities, established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes.

We had unrestricted cash and cash equivalents totaling approximately $62.2 million, $28.9 million and $27.2 million at December 31, 2009 and 2010 and March 31, 2011, respectively. These amounts were invested primarily in demand deposit savings accounts and are held for working capital purposes. At December 31, 2010, approximately $6.0 million was invested in commercial paper with maturities of less than three months. Also at December 31, 2010, approximately $8.0 million, classified as a short term investment, was invested in commercial paper with maturities of less than twelve months. The primary objective of our investment activities is to preserve our capital for the purpose of funding our operations

Management’s discussion and analysis of financial condition and results of operations

including acquisitions. We do not enter into investments for trading or speculative purposes. We believe we do not have material exposure to changes in fair value as a result of changes in interest rates. Declines in interest rates, however, will reduce future investment income. If overall interest rates fell by 10% in 2010, and the three months ended March 31, 2011, our interest income would have declined by approximately $5,400 and $1,100, respectively, assuming consistent investment levels.

The terms of our loan and security agreement provide for a fixed rate of interest, and therefore are not subject to fluctuations in market interest rates.

We produce methane, the primary component of natural gas. The demand for natural gas generally increases during the winter months and in some areas during the summer, and decreases during the spring and fall months. Seasonal anomalies such as mild winters and hot summers, and extreme weather events, can lessen or intensify this fluctuation and amplify localized price spikes. Other natural gas price factors include North American E&P, and the amount of natural gas in underground storage during both the injection and withdrawal seasons. We attempt to reduce the market risk associated with fluctuations in the price of natural gas by employing a variety of risk management and economic hedging strategies, including the use of commodity contracts.

All of our employees are located, and all of our major operations are currently performed, in the US. We occasionally pay for contractor or research services in a currency other than the US dollar. Today, we have minimal exposure to fluctuations in foreign currency exchange rates as the difference from the time period for any services performed which require payment in a foreign currency and the date of payment is short.

On January 1, 2009, we adopted ASC 815-40, Derivatives and Hedging —Contracts in an Entity’s Own Equity. ASC 815-40 was issued in June 2009 and provides guidance for determining whether an equity-linked financial instrument or embedded feature is indexed to an entity’s own stock. ASC 815-40 requires additional analysis as to whether an instrument or embedded feature has anti-dilution provisions that may result in liability classification and is effective for financial statements issued for fiscal years beginning after December 15, 2009. Upon adoption in 2009, we reclassified the fair value of the warrant issued to Silicon Valley Bank in 2009 (see Note 4 to our consolidated financial statements included elsewhere in this prospectus) to a liability due to its embedded anti-dilution feature, which was not deemed to be indexed to our common stock.

In January 2010, the FASB issued an Accounting Standards Update (ASU) 2010-03, Extractive Activities —Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosure. This ASU amends the FASB accounting standards to align the reserve calculation and disclosure requirements with the requirements in the recently adopted SEC rule, Modernization of Oil and Gas Reporting Requirements. The ASU is effective for reporting periods ending on or after December 31, 2009, and will be adopted on a prospective basis as a change in accounting principle inseparable from a change in estimate. We have adopted ASC 932 effective January 1, 2010 and are now using the successful efforts method of accounting on a prospective basis. Prior to 2010, we had not adopted the requirements of ASC 932 as our natural gas properties are nontraditional resources. It is impractical to calculate the current year impact to the loss from continuing operations, net loss, and other applicable financial line items.

We were formed as Clearflame Resources LLC, a Delaware limited liability company, in April 2003 and changed our name to Luca Technologies LLC in July 2004. We converted into a Delaware corporation on April 20, 2007. In addition to the initial funding by our founders, we have successfully concluded a series of venture capital and private equity offerings between 2006 and 2008 totaling approximately $99 million. Our financial partners include Kleiner Perkins Caufield & Byers, One Equity Partners, Oxford Bioscience Partners and BASF Venture Capital.

Our technology allows us to economically and sustainably create natural gas from current wells, thereby utilizing and extending the life of existing natural gas infrastructure, and minimizing our need for new drilling. We produce this newly created natural gas from existing wells and deliver it to the natural gas market via existing pipelines. Unlike the traditional E&P industry’s extraction methods in which production peaks and then steeply declines as stored hydrocarbons are depleted, we believe, based on lab and field results, that our Restoration Process economically and sustainably creates low-cost clean energy for many years. We believe our technology competes favorably with the traditional “hunter/gatherer” style of natural gas development (find, drill, produce, then abandon) by allowing a “farming” style of natural gas creation (restore, feed, grow, then harvest), which continually produces a new crop of natural gas.

Our operations are initially focused in the PRB where we currently own and operate more than 1,350 wells. We intend to acquire additional wells in the PRB and expand our operations to multiple basins in the United States and abroad. From 2006 through March 2010, we performed our Restoration Process on over 400 wells in the PRB under a pilot program regulated by the WOGCC. As we moved towards commercialization, new legislation was required to permit the circulation of our nutrient formulations on a commercial scale. Pending the completion of this legislative process, we elected to shut-in a majority of our wells in 2010 to conserve water. The legislation was passed in February 2011 and the rules implementing this legislation are expected to be finalized by the fall of 2011. As a result, we expect to obtain required regulatory approvals in that time frame. Once that process is complete, we expect to resume our Restoration Process on our wells in Wyoming.

Our goal is to be the global market leader in biogenic methane gas creation and production. For more on methane gas creation, see “—Gas Creation.” We anticipate growing our business primarily through acquiring natural gas properties, applying our Restoration Process to create new sustainable sources of natural gas, and producing and selling this natural gas to existing markets. In the future, we may expand our efforts to include oil and organic-rich shales.

Our Restoration Process creates methane gas. Methane (CH₄) is the simplest hydrocarbon molecule and is comprised of one carbon atom and four hydrogen atoms attached via covalent bonds. According to the EIA, methane is the cleanest burning form of natural gas.

Most natural gas, including methane, is created by either thermogenic or biogenic geologic processes. Thermogenic generation involves the conversion of deep organic sediment material by extreme pressure and heat into coal, oil or natural gas. In contrast, in biogenic generation, anaerobic microorganisms that have lived in subsurface coal and other hydrocarbon deposits for millions of years, convert carbon and hydrogen-rich organic matter to natural gas as part of naturally occurring processes.

Traditionally, both thermogenic and biogenic methane deposits have been considered dormant, i.e., created in the geological past and no longer evolving. Recent evidence, however, has proven that the biogenic production of methane in certain coal deposits is an ongoing process in many large hydrocarbon reservoirs in the US and abroad. When properly managed, these reservoirs, many already accessible through previously drilled wells, can be turned into biogenic “gas farms,” where the already existing microbial communities can be enhanced to produce commercial quantities of methane in real-time. We believe this enhanced biogenic gas creation process may have the potential to help meet US energy needs for the foreseeable future, at a fraction of the cost of traditional E&P.

We leverage the ability of naturally occurring microorganisms to convert subsurface hydrocarbon deposits, such as coal, to methane gas. This complex process is susceptible to interruption by various chemical and biological conditions, including traditional coalbed methane development which involves removing water from the coal seam to reduce pressure and allow previously adsorbed natural gas to flow up a well. As a result, the natural and ongoing biogenic creation of methane gas slows or ceases, with a large mass of unutilized hydrocarbon deposit remaining in place underground. To accelerate biogenic methane gas production rates, we use our proprietary Restoration Process to deliver customized nutrient formulations and water to restore coal reservoir habitats to conditions that may enable native microbial communities to be enhanced to create commercial volumes of natural gas on a real-time basis. We produce this newly created natural gas and deliver it to market using existing wells, pipelines and natural gas infrastructure.

Oil and natural gas resources developed and produced by the traditional E&P industry often exhibit production rates that peak early in the lives of wells, and then steeply decline as stored hydrocarbons are depleted and pressure is reduced. In contrast, wells producing newly created methane gas using our Restoration Process are more akin to “gas farms,” producing natural gas at lower, but constant or slightly increasing rates for extended periods of time.

Our Restoration Process is designed to sustain the life processes of naturally occurring microbial communities. We do not introduce foreign microbes, nor do we rely upon genetically-engineered microorganisms. Microbes are already present in coalbed water and are responsible for biogenic methane gas creation. The first step in our Restoration Process involves the identification and assessment of underground environments where the native conditions are suitable for microbial life activation, and where the biogenic process has been active in the past. As a second step, we perform lab and field studies to assess microbial activation. In the lab, using water and hydrocarbon deposits from a prospective basin, we attempt to identify optimal nutrient formulations for methane creation. These nutrient formulations are then field-tested prior to initiation of commercial activity within an area or basin. The table below indicates the types of nutrients used and their common commercial use.

The third step of our Restoration Process involves circulating our proprietary nutrient formulation to target microbes in the underground reservoir to support the creation of new methane. Nutrient delivery is performed using a mobile nutrient delivery system, which is temporarily installed at a well site. This delivery system houses secure storage of the nutrients, plus the blending and metering equipment needed to control the rate at which nutrients are provided to the microbes in the underground reservoir.

Our Restoration Process can be applied in two ways. Although most of our restoration activities to date have used a “push-pull” delivery method, which is more akin to a batch process, we are beginning to transition to a “gas farming” method that involves the continuous flow of our nutrient formulations.

Since 2006, we have performed over 500 restoration projects on coalbed methane wells, including over 400 located in the PRB. The results of these activities demonstrate that our Restoration Process creates new methane gas. Due to the geologic characteristics of the coal seam and its permeability, new incremental natural gas production is measured from not only the well treated with our Restoration Process, but also from surrounding wells. Based on historical results, average incremental daily natural gas production from the push-pull method starts approximately six months following a treatment, grows to a plateau rate of approximately 25 to 30 Mcf of natural gas per day, and remains at this level for several years. We anticipate that a slow decline in production will follow. However, our most comprehensive demonstration project, involving more than 260 PRB wells, is now more than four years old, and plateau rates of production appear to be stable with minimal decline. We believe that gas farming will lead to similar, if not greater, rates of natural gas production as nutrients are constantly fed to the microbes over time, leading to sustainable levels of natural gas production.

We have also performed restoration activities in several basins outside of Wyoming, including the Black Warrior Basin in Alabama, the San Juan Basin in New Mexico and the Uinta Basin in Utah, as well as other areas in Oklahoma, Kansas, and Illinois. At this time, we do not own wells in these areas, but have deployed our technology in wells owned by other operators interested in determining if the technology will be applicable in areas other than the PRB. Based upon preliminary results from these projects, combined with lab results from sampling activities performed in these areas, we believe our Restoration Process with formulations tailored for local conditions, will prove to be economic in other gas fields throughout the United States and abroad.

Our success depends in large part on our proprietary technology for which we seek protection under patent, copyright, trademark and trade secret laws. Such protection is also maintained in part by using proprietary information and invention agreements. Protection of our technology is important so that we may exclude our competitors from practicing technology that we have developed. If competitors in our industry have access to the same technology, our competitive position may be adversely affected. As of the date of this prospectus, we have 12 issued US and foreign patents, two US and foreign patent applications that are currently allowed and awaiting issuance, and 36 pending US and foreign patent applications. These patents and patent applications are directed to our technology and the specific methods that support our business. We continue to file new patent applications, for which terms extend up to 20 years from the earliest priority filing date in the US. As of the date of this prospectus, we have obtained a license on a non-exclusive basis to rights under one issued US patent.

We will continue to file and prosecute patent applications and maintain trade secrets, as is consistent with our business plan, in an ongoing effort to protect our intellectual property. The patent positions of companies like ours are generally uncertain and involve complex legal and factual questions. Our pending US and foreign patent applications may not issue as patents or may not issue in a form that will be advantageous to us. Any patents we have obtained or do obtain may be challenged by re-examination, opposition or other administrative proceeding, or may be challenged in litigation, and such challenges could result in a determination that the patent is invalid. The same challenges may be faced by any patent applications or patents for which we obtain a license. Under appropriate circumstances, we may sometimes permit certain intellectual property to lapse or go abandoned. Due to uncertainties inherent in prosecuting patent applications, sometimes patent applications are rejected and we may subsequently abandon them. It is also possible that we may develop products or technology that will not be patentable or that the patents of others will limit or preclude our ability to obtain patents and do business. In addition, any patent issued to us may provide us with little or no competitive advantage, in which case we may abandon such patent or license it to another entity.

In addition to pursuing patents on our technology, we have taken steps to protect our intellectual property and proprietary technology by entering into proprietary information and inventions agreements with our employees, consultants, contractors and, when needed, our other advisers. We have also taken steps to prevent our employees from bringing the proprietary rights of third parties to us. We also use confidentiality or material transfer agreements with third parties that receive our confidential data or materials. Such agreements may not be enforceable or may not provide meaningful protection for our trade secrets or other proprietary information in the event of unauthorized use or disclosure or other breaches of the agreements, and we may not be able to prevent such unauthorized disclosure. Monitoring unauthorized disclosure is difficult, and we do not know whether steps we have taken to prevent such disclosure are, or will be, adequate.

that it can be sold directly into existing markets using existing infrastructure. Clean, biogenic, domestically-produced natural gas is an accessible and more environmentally friendly energy alternative, which is expected to play an increasing role in advancing both environmental and energy policy goals in the United States. Clean and renewable energy sources are becoming increasingly important for the United States, which has historically been a net importer of petroleum. There has been growing concern over CO₂and other emissions that are especially prevalent from burning coal and fuel oil. According to the EIA, methane is the cleanest burning fossil fuel, with approximately 117 lbs. of CO₂ produced per 1 million Btu equivalent of natural gas, compared to 160 lbs. of CO₂ for fuel oil and 200 lbs. for coal. Conversely, natural gas delivers 71% more energy per unit of CO₂ emitted relative to coal.

Our technology offers the potential to expand domestic energy production, while minimizing the need to expand the footprint of the oil and natural gas industry’s producing areas. According to the EIA, demand for natural gas in the United States and globally is projected to grow at annual growth rates of 0.5% and 1.9% through 2035, respectively. The IEA has identified several factors that could accelerate growth in demand for natural gas in the coming years, including potentially faster acceptance of CNG vehicles, recent policy changes in China promoting the production, import and use of natural gas, and a more restricted outlook for nuclear power in the wake of the Fukushima nuclear power plant disaster in Japan.

As shown in the graphic below, there are a number of important coalbed methane gas fields in the United States.

While the natural gas market is largely commoditized, the emergence of new, cleaner methods for natural gas production and energy extraction has the potential to create a differentiation between natural gas produced using traditional methods and new sustainable production. Several US states have recently introduced renewable portfolio standards, requiring a certain portion of their energy supply be derived from renewable sources. With the intermittence of solar and wind power, natural gas has the potential to fill this intermittent gap. We may in the future pursue legislation to qualify our biogenic methane gas as a renewable energy resource.

The variety of seasonal, geopolitical and economic factors at play in the natural gas markets affects natural gas prices along the entire chain from producers to consumers. The demand for natural gas generally increases during the winter months and in some areas during the summer, and decreases during the spring and fall months. Seasonal anomalies such as mild winters and hot summers, and extreme weather events, can lessen or intensify this fluctuation and amplify localized price spikes. Most natural gas sold in North America is priced against Henry Hub, the actual physical interconnection point on the natural gas pipeline in Louisiana where natural gas is typically delivered. The Henry Hub price is typically seen as the primary price setting mechanism for the North American market, although the physical distance from the Hub will impact prices around the country.

Given our primary focus on the PRB, we expect the majority of our production to be sold directly into the main transportation infrastructure of the CIG. Due to the physical distance of the PRB from the Henry Hub, we expect our pricing to reflect a discount differential to Henry Hub prices, consistent with recent historical trends. The chart below highlights the historical volatility trend for natural gas prices observed from 2004 through 2011.

Natural gas withdrawn from a well may contain liquid hydrocarbons and non-hydrocarbon gases. Natural gas is separated from these compounds near the production well or at a processing facility, to form consumer-grade “dry natural gas” which is ready for transportation to the local distribution hub and ultimately to the consumer. According to the EIA, there are approximately 300,000 miles of natural gas pipelines in the United States, including over 188,000 miles of wide-diameter, high-pressure interstate and intrastate mainlines. Due to the purity of the methane gas created using our technology, our production does not typically require any processing or treatment and is readily delivered to the national transportation infrastructure and ultimately, to the end users.

The chart below illustrates the transportation of our natural gas from the wellhead to the end users.

Our business and operations are subject to numerous laws and regulations, including certain energy, environmental, conservation and other laws and regulations relating to the energy industry. Most of our operations require permits or authorizations from federal, state or local agencies. Changes in any of these laws and regulations or the denial or withdrawal of permits or authorizations could have a material adverse effect on our business. In view of uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

The oil and natural gas and coalbed methane industries are extensively regulated by numerous federal, state and local authorities, including Native American tribes. Legislation affecting the oil and natural gas and coalbed methane industries is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous federal, state, local, and Native American tribal departments and agencies are authorized by statute to issue rules and regulations binding on the oil and natural gas and coalbed methane industries and their individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas and coalbed methane industries increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industries and similar types, quantities and locations of production, except as described below.

Under federal law, the Mineral Leasing Act, as amended, authorizes the Secretary of the Interior to lease rights to extract federal minerals including, oil and natural gas, coal and coalbed methane. Through the Federal Land Policy and Management Act, the Secretary of the Interior delegated this mineral leasing authority to the BLM. We currently own and expect to acquire in the future interests in federal minerals under these laws. As a result, we will also be subject to the federal regulations related to these laws.

The law is not settled as to whether an oil and gas lessee has the right to accelerate the natural production of biogenic coalbed methane without authority from the coal estate. Our technology may be viewed as an acceleration of the naturally occurring process of the conversion of coal to gas and thus our technology could be viewed to burden, damage or, in the absence of federal authorization, trespass on the coal estate. In instances where the federal government is the severed coal estate owner, the BLM or the Office of the Solicitor will likely request us to consider (i) the requirement of additional legal authorization for the impacts to federal coal, (ii) payment of an impact fee and (iii) an agreement on how to resolve any coal conflicts that develop. For areas of federally owned coal, we are actively working with the BLM to develop a permit that will allow us to implement our technology in these areas.

Our PRB operations are subject to various types of regulations at federal, state, local and Native American tribal levels. These types of regulation include requiring permits for drilling wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities and Native American tribes also regulate one or more of the following:

Our operations in the PRB will require us to combine our leases together into “units” under the WOGCC rules and regulations. These units allow us to implement our technology and ensure that all the owners of the various interests equitably share in production, e.g., if a certain royalty owner’s well is converted to an injection well, such owner will share in royalties with the wells that are producing wells. Wyoming law allows us to file an application with the WOGCC requesting an order authorizing injections to restore or enhance the microbial conversion of hydrocarbon deposits to methane gas. If the application is submitted on a unit basis, an order of the WOGCC authorizing the commencement of unit operations will not become effective until a unitization plan has been ratified or approved by at least 80% of all royalty owners and 80% of all working interest owners.

Prior to approving the application, the WOGCC also requires the applicant to obtain either a Class II injection well permit from the WOGCC or a Class V injection well permit under the SDWA from the WDEQ. For more on these permits, see “—Environmental Regulation—Underground injection control.” For the foreseeable future, we expect to use Class V injection well permits for our Wyoming operations.

Our activities are also managed and regulated based on their impact to certain wildlife. A critical habitat designation for certain wildlife under the US Endangered Species Act or similar state laws could result in further material restrictions to governmental land use and private land use and could delay or prohibit land access or development. The listing of certain species, such as the sage grouse, as threatened and endangered, could have a material impact on our operations in areas where such listed species are found.

The transportation of natural gas and its component parts is regulated under federal, state and local rules. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission, or FERC, has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Various federal laws enacted since 1978 have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of our sales of our own production. Under the Energy Policy Act of 2005, the FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

The FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, the FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. The FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less

stringent regulatory approach currently pursued by the FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under the FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, the FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting natural gas to point-of-sale locations.

The Occupational Safety and Health Act, or OSHA, and comparable state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

We and traditional natural gas E&P operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment. The environmental laws and regulations that could have a material impact on the natural gas industry and our business include:

NEPA requires federal agencies, including the BLM, to evaluate environmental impacts of major federal actions having the potential to significantly affect the quality of the human environment. Federal actions subject to NEPA review include the leasing of federal lands and associated federal rights in natural resources, including oil, natural gas and coal. Federal actions also include issuance of federal permits. Some of our production activities are planned to occur on federal leases. In the course of a NEPA evaluation if an action involved is determined to be major, an environmental assessment will be prepared to assess the potential direct, indirect and cumulative impacts of a proposed federal action. If impacts are considered significant, the BLM will prepare a more detailed EIS that is made available for public review and comment. Although NEPA requirements are considered procedural rather than substantive, challenges to the adequacy of compliance with NEPA requirements, including possible litigation, can result in delay or even halt a project.

Production operations on federal leases are generally performed in accordance with a Record of Decision, or ROD, issued by the BLM after preparation of an EIS. A ROD typically includes environmental and land use provisions that restrict and limit exploration and production activities on federal leases. To the extent we may be subject to ROD requirements, we do not expect any material difficulty in complying with such terms and conditions.

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes impose regulations on the generation, transportation, treatment, storage, disposal and cleanup of certain “hazardous wastes” and on the disposal of non-hazardous wastes. The individual states may administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. We generate wastes, some of which may be hazardous wastes subject to RCRA and comparable state statutes. The EPA and various state agencies have imposed requirements on the transport, treatment and storage of such wastes and limited the disposal options for them. Furthermore, it is possible that certain wastes generated by our natural gas operations that are currently exempt from regulation as hazardous waste may in the future be designated as hazardous waste under RCRA or other applicable statutes, and therefore may be subject to more rigorous and costly operating and disposal requirements.

Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of natural gas constitute “solid wastes,” which are regulated under the less stringent, non-hazardous waste provisions of RCRA. There is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes, which could increase our costs to manage and dispose of such wastes.

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes strict, joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for a release or threatened release of a “hazardous substance” into the environment. These persons include the current and certain past owners or operators of a facility where there is or has been a release or threatened release of a hazardous substance, and those that disposed or arranged for the disposal of a hazardous substance at the site.

Under CERCLA, such persons may be subject to liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for certain other costs. We have not been named as a person responsible under CERCLA for remediation of hazardous substances. In addition, neighboring landowners and other third parties may file tort or other claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Our Restoration Process is designed to avoid surface water discharge and circulate water within the formation. Permitting for this process will be handled under the Underground Injection Control permits described below. In the event that our operations require us to surface discharge water, we would be subject to certain regulatory requirements. The Federal Water Pollution Control Act, also known as the Clean Water Act, or CWA, and analogous state laws impose restrictions on the surface discharge of pollutants, including produced waters and other natural gas wastes, into certain regulated waters of the US. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, or the state. Such permits may include a limitation on the volume of an authorized discharge. These prescriptions also prohibit the discharge of dredged or fill material into waters of the US, including jurisdictional wetlands, unless authorized by a permit issued by the US Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties, as well as other enforcement remedies for non-compliance with discharge permits or other

requirements of the CWA and analogous state laws and regulations. Obtaining permits may delay the development of natural gas projects and limit the total volume of water that can be discharged, which may limit the rate of development.

The SDWA and comparable state statutes regulate the subsurface emplacement of fluids and impose requirements on certain underground injection of fluids, including produced water, to protect public drinking water. Injection of fluids is governed by federal or state regulatory authorities which may include the state oil and natural gas regulatory authority or the state’s environmental authority. These regulatory requirements may increase the cost of compliance for some facilities.

Regulators may view our technology as an injection subject to the requirements of the SDWA. Many states have been authorized to implement SDWA requirements and regulate injection wells within their boundaries. In Wyoming, the WDEQ regulates SDWA Class V injection wells involving injections into freshwater aquifers and the WOGCC regulates SDWA Class II wells involving injection into oil and natural gas reservoirs. In the PRB, our injections will be into freshwater aquifers. We, therefore, are required to receive Class V permits from the WDEQ. Under the new Wyoming state legislation passed in February 2011, we are allowed to secure a Class V permit from the WDEQ and use that WDEQ permit for approval of a unit and authorization of our Restoration Process in the necessary WOGCC applications and hearings. The proposed rules to implement this legislation have been released for public comment and a hearing on the proposed rules is set for August 2011. We expect the rules should be made final sometime later this year. Once the rules are final, we will be able to implement our technology under this new legislation.

To inject our nutrient formulations into fresh water in states other than Wyoming, we may be required to work with multiple regulatory agencies to permit our Restoration Process, and we may be required to seek legislative changes in other states. We cannot guarantee that we will be able to successfully resolve the various underground injection control permitting issues in each state in which we seek to deploy our technology.

In addition, while we do not currently utilize hydraulic fracturing in our operations as a means of maximizing the productivity of our wells, we may utilize fracturing in connection with our operations in the future. Although injection of fluids in connection with hydraulic fracturing operations related to natural gas production is now exempt from the SDWA underground injection control requirements, heightened debate over whether the fluids used in hydraulic fracturing may contaminate drinking water has led to increased scrutiny of the practice and to various federal and state proposals to impose restrictions on fracturing operations. For example, the EPA has recently asserted authority over certain hydraulic fracturing operations (which are being contested in litigation by industry groups) and is collecting information as a part of a study into the effects of hydraulic fracturing on drinking water due to be completed in 2012. In addition, some states have issued or are considering moratoria on certain new natural gas development and some (including Wyoming) now require disclosure of hydraulic fracturing fluid content. At this time, it is not possible to predict the final outcome of EPA’s study or any new federal or state requirements that may affect hydraulic fracturing. Any new restrictions imposed on the use of hydraulic fracturing could have a significant impact on our business, financial condition and results of operations.

We are subject to federal, state and local requirements that control emissions from sources of air pollution. Administrative enforcement actions for failure to comply strictly with air regulations or permits may be resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could impose civil or criminal liability for non-compliance. An agency could require us to forego construction or operation of certain air emission sources.

Our coalbed methane operations will likely involve the use of natural gas-fired generators and compressors to transport natural gas that we produce. Emissions of nitrogen oxides and other combustion by-products from individual or multiple generators and compressors at one location may be great enough to subject the compressors to federal and state air quality requirements for pre-construction and operating permits. We cannot guarantee that we will not have significant delays or problems in obtaining any required air permits or that we will be able to operate these generators and compressors in compliance with permits and applicable federal, state and local laws and regulations without undue cost or burden to our business activities. In addition, particulate matter resulting from construction activities and vehicle traffic at our locations may be subject to air permitting requirements. We cannot guarantee that we will not experience any difficulty complying with any potentially applicable environmental requirements related to particulate matter and that we will not need to obtain permits relating to particulate matter.

According to certain scientific studies, emissions of carbon dioxide, methane, nitrous oxide and other gases commonly known as greenhouse gases, or GHG, may be contributing to global warming of the earth’s atmosphere and to global climate change. In response to the scientific studies, legislative and regulatory initiatives on the federal, regional, state and local levels are underway to limit GHG emissions. The US Supreme Court determined that GHG emissions fall within the federal Clean Air Act, or CAA, definition of an “air pollutant,” and in response the EPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. The EPA has also promulgated rules requiring certain large sources to report their GHG emissions, including certain upstream oil and natural gas facilities. Regulations may be expanded in the future to apply to additional GHG sources. Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact our operations. Further, apart from these developments, recent judicial decisions that have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase our litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, we cannot predict the financial impact of related developments on us.

We view traditional E&P companies, other biogenic gas creation companies and alternative clean energy companies as our main competitors.

The traditional E&P industry is intensely competitive and many of our competitors in this industry have greater resources than us. Although our methane is similar to natural gas from other sources, we believe that our process differentiates us from traditional E&P companies. Our natural gas is created and produced in real-time in a sustainable manner, rather than extracted in a rapidly depleting manner from

stored and finite resources. We believe the economics of our Restoration Process are more favorable than that of traditional E&P companies. Our ability to reuse existing wells and infrastructure substantially reduces our capital investments, and provides significant competitive cost advantage relative to shale and traditional E&P companies.

Access to resources on which we can deploy our technology is critical to executing our business plan. Most resources suitable for our process are presently owned by traditional E&P producers. We intend to acquire such properties and will likely encounter competition from other producers who see value in owning the properties. Where we cannot acquire properties, we may form partnerships with owners to deploy our technology.

We are aware of other companies developing and/or planning to commercialize bioconversion technology that is similar to or potentially overlaps with our technology portfolio. These companies include Ciris Energy, Inc., or Ciris, Synthetic Genomics, Inc., or SGI, and Next Fuel, Inc., or Next Fuel.

Ciris is a privately owned company based in Centennial, Colorado. Ciris’ patents suggest they use a bioconversion process that involves injecting both chemicals and nutrients down coalbed methane wells. The chemicals serve to solubilize a fraction of the coal and nutrients stimulate microbes to produce methane. We understand that Ciris has had limited application of its technology in the field.

SGI is a privately owned company based in La Jolla, California which conducts a broad range of research on next generation fuels and chemicals, hydrocarbon recovery and conversion, and agricultural products. In June 2007, BP invested in SGI and established a multi-year, research and development collaboration joint venture focused on microbial-enhanced solutions to increase hydrocarbon recovery. We believe SGI may not be restricting their process to use of native, and/or genetically unmodified micro-organisms as we have done.

Next Fuel is a public company (OTCQB: NXFI) with a coal to gas process. We understand that Next Fuel’s process re-introduces amendments that have been designed and tested to the wide range of microorganisms that exist in seams of coal and other carbonaceous deposits. Next Fuel’s proprietary amendments consist of constituents with depolymerizing and structure-altering functions to “condition” coal for the follow-up pathways for gas production. Because of the use of coal depolymerizing and structure-altering chemicals, we believe Next Fuel’s process may be suited for underground environments different from those available to our Restoration Process.

Production of electricity is one of the primary uses of natural gas. Several other clean technologies are used to produce electricity including wind, solar, hydro, geothermal, and nuclear power. Although these technologies produce only a minor percentage of all electricity, several are experiencing fast growth rates. In addition, many national and local governments are promoting and subsidizing the use of one or more of these technologies. As a result, we view these alternatives as competitors to our Restoration Process in the clean energy sector.

While natural gas-fired technologies compete for a share of the clean energy market with alternative clean technologies, they can also be used to complement those that produce power intermittently like wind and solar. Intermittent sources generally require backup capacity. In many markets, gas-fired power plants are increasingly used to balance demand loads.

Natural gas can also be used as a low CO₂ transportation fuel for CNG vehicles. As a result, our Restoration Process competes with a range of biofuel technologies that produce alcohols, bio-gasoline, bio-diesel, and bio-jet fuel.

Our primary geographic area of activity, and currently the only area in which we own and operate wells is the PRB. The greater PRB traverses about 90 miles from east to west and 200 miles from north to south, encompassing portions of northeastern Wyoming and southeastern Montana. The PRB, with continuous wide-spread thick coal seams, an extensive natural gas production infrastructure, water chemistry well suited to microbial methane bioconversion, and exceptional permeability for the efficient delivery of nutrients and production of natural gas among wells, has been our primary focus for the past eight years and will play a critical role in our future growth.

According to the EIA, the PRB accounts for approximately 42% of coal production in the United States and is the single largest source of coal mined in the United States. The majority of the coal in the basin is owned by the federal government and administered by the BLM. Oil and natural gas mineral rights are primarily held by private individuals along with significant federal and state ownership. The surface is rolling grasslands and is owned by federal and state agencies, along with private individual ranchers who may not have ownership of mineral rights under their property.

The PRB has undergone extensive coalbed methane development and is one of the largest accumulations of biogenic methane gas in the world. According to the WOGCC, to date over 30,000 wells have been drilled to develop the resource in Wyoming. At present, many coalbed methane operations in the basin are economically challenged and, according to the WOGCC, approximately 12,000 wells are shut-in or dormant as a result of mature, low rate production and current natural gas prices. We believe this situation will present us with a number of opportunities to acquire properties at attractive prices.

We presently own and operate over 1,350 wells in the PRB, many of which are currently shut-in, and have over 89,000 gross (75,000 net) acres held by production and approximately 110 miles of associated natural gas gathering pipelines and equipment. We control a producing infrastructure consisting of wells, equipment and natural gas gathering lines. Our intent is to expand our present holdings in the PRB through acquisitions of wells, thereby expanding our control of the basin’s significant bioresource. We plan to also continue acquiring gathering systems, reconfiguring transportation options and lowering those costs. As we progress, we will focus on projects of scale in the basin, forming additional production units, deploying our technology, and increasing our natural gas creation and production volumes, and cash flow.

To comply with the requirements of Rule 4-10 of Regulation S-X as of December 31, 2010 and ASC 932 as adopted in 2010, we have compiled an internal reserve report for our natural gas properties, including estimated production, reserves, and net cash flows resulting from deployment of our Restoration Process. We do not believe proved reserves are a meaningful metric for valuing our company given that our technology creates new methane gas in real-time. We expect to increase proved reserves in the future and to demonstrate that our Restoration Process is a reliable technology in other areas outside of the PRB.

In estimating the volumes of reserves of natural gas that will be created from the deployment of our Restoration Process into coal seams in the PRB, our reservoir engineers rely principally on their observations of the production responses obtained from our field demonstration projects, which used our initial delivery process. Interpreted responses are then applied to analogous underground reservoir environments, sometimes after application of slight risking modifications to recognize local conditions. We do not recognize reserves for areas that have not undergone a pilot-phase field test that has shown positive early results. To date, no data from laboratory gas-creation studies has been used in the calculation of reserves.

Total proved reserves recorded at December 31, 2010 were 5.5 Bcf of natural gas and relate to anticipated production from approximately 200 wells that have demonstrated a positive response from our Restoration Process.

In the future, we anticipate estimating reserves using calculations that utilize a combination of the ongoing performance of our field demonstration projects, and the early and expanding performance of other projects utilizing our gas farming method. Assessment and documentation of analogous environments will utilize geological, geochemical, microbiological and production data. Future reserve estimates may also utilize results from future laboratory studies conducted using new flow-cell systems which more closely resemble reservoir conditions.

The following table sets forth certain information about our estimated proved reserves as of December 31, 2010:

As of December 31, 2010, we had no proved undeveloped reserves or proved developed non-producing reserves. Estimated future costs related to our gathering system and plugging and abandonment costs are expected to total approximately $1.7 million.

The estimated cash flows from our proved reserves at December 31, 2010 were as follows:

We have not filed any reports with other federal agencies that contain an estimate of total proved net natural gas reserves.

The technical person primarily responsible for overseeing preparation of the reserves estimates and supervising the third party reserves audit is the Vice President of Engineering. His qualifications include 35 years of broad reserves and evaluation experience in numerous domestic and international basins, and management of the reserves books at large and small natural resource companies. He holds the degrees of B.S. in Chemical Engineering and Master of Business Administration, and is a member of the Society of Petroleum Engineers.

Ryder Scott conducted a reserves audit of the estimates of the proved reserves, future production and discounted future net income as of May 31, 2011 prepared by our engineering staff. It is Ryder Scott’s opinion that the overall procedures and methodologies utilized by us in preparing our estimates of the proved reserves, future production and discounted future net income as of May 31, 2011 comply with the current SEC regulations and that the overall proved reserves, future production and discounted future net income for the reviewed properties as estimated by us are, in the aggregate, reasonable within the established audit tolerance guidelines of 10% as set forth in the auditing standards of the Society of Petroleum Engineers. Our estimated proved reserves as of such date were 5,341 MMcf and the standarized measure of discounted future net cash flows was approximately $1.4 million. Comparable procedures and methodologies were utilized by us to arrive at our estimates of reserves at December 31, 2010 and March 31, 2011.

New science and technology advancement are the basis of our Restoration Process and underpin our ability to produce biogenic methane at a cost that is competitive with traditional natural gas producers. We plan to continue to invest significantly in R&D to increase the rate and yield of methane gas creation from coal and to deploy our technology to new basins.

Our R&D effort is aimed at gaining an understanding of the nature and relationship between hydrocarbon deposits, water and microbes in order to quickly and accurately customize treatments for increased production rate and yield, and optimize the hydrocarbon conversion process. We also look to broaden the applicability of our technology across different ranks of coals and in a broader range of coalbed environments (e.g., more saline environments) and other geographic locations.

Our R&D initiatives have been established around a fundamental principle that the type of catalysts present in hydrocarbon deposits have the most profound effect on the rate of methane formation and that yield may be affected based on the choice of catalyst used. The biogenic creation of new natural gas from subsurface hydrocarbon deposits is predicated on the conversion of coal to the molecules used by microorganisms to make methane.

The following table shows our research and development costs by function during the three years ended December 31, 2008, 2009 and 2010, in thousands:

As of the date of this prospectus, our R&D department consists of 46 employees, eight of whom hold PhDs.

The following table sets forth our sales volumes, the average prices we received before hedging, the average prices we received including hedging gains (losses) and average production costs associated with our sale of natural gas for the periods indicated. We account for our hedges using the normal purchase and sale exception permitted under ASC 815, Derivatives and Hedging, and accordingly are not required to apply its provisions to the fixed price contracts. As a result, no asset or liability has been recorded for the fair value of these contracts in the accompanying financial statements. We have elected to include the gains and losses from these contracts within revenue.

We have not drilled any exploratory or developmental wells in any of the previous three fiscal years ended December 31, 2008, 2009 and 2010.

During this time period, we have performed other developmental activities similar to enhanced recovery techniques in the form of our Restoration Process. We have performed our Restoration Process on third party wells and wells we own and operate within the PRB on 421 occasions and we have performed our Restoration Process on wells in which we do not have an operating interest outside of the PRB on 110 occasions. The following table summarizes this development activity for each of the past five fiscal years and the first quarter of 2011.

The following table shows the number of producing wells and wells capable of production that we owned by area at December 31, 2010:

The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage by area as of December 31, 2010:

The table below summarizes, as of December 31, 2010, our undeveloped acreage scheduled to expire by year.

We have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three years. As is customary in the natural gas industry, we can retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by payment of delay rentals during the primary term of such a lease. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have allowed acreage to expire and may allow additional acreage to expire in the future.

Additionally, we have several large federal leases with portions that currently have no development on them. Although the federal government has allowed the entire leased area to be held by us based on production from a portion of the leased area to this point, the federal government has the right to segregate the undeveloped tracts and treat those parts as undeveloped. We could therefore forfeit those undeveloped tracts at some point in the future if we do not develop them.

We believe that title to our natural gas properties is good and defensible in accordance with standards generally accepted in the natural gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. Our properties are typically subject, in one degree or another, to one or more of the following:

To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and obligations affecting our properties are conventional in the industry for properties of the kind that we own.

Our operations are affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. Generally, the demand for natural gas decreases during the spring and fall months and increases during the winter months and in some areas during the summer months. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. Conversely, during extreme weather events such as blizzards, hurricanes, or heat waves, pipeline systems can become temporary constraints to supply meeting demand thus amplifying localized price spikes. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the warmer months. This can lessen seasonal demand fluctuations. World weather and resultant prices for liquefied natural gas can also affect deliveries of competing liquefied natural gas into this country from abroad, affecting the price of domestically produced natural gas. In addition, adverse weather conditions can also affect our production rates or otherwise disrupt our operations.

Our corporate headquarters are located in Golden, Colorado, where we occupy approximately 28,200 square feet of office and laboratory space. Our lease for this facility expires on June 30, 2012 but can be extended for an additional three years under similar terms. We believe that this facility is adequate for our needs for the immediate future and that, should it be needed, additional space can be leased to accommodate any future growth. We also lease a field production office and mixing facilities in Gillette, Wyoming.

As of the date of this prospectus, we employed 72 full-time employees. Of these employees, 56 were located in Golden, Colorado and 16 were located in Gillette, Wyoming. Of these employees, 46 were engaged in research and development activities and 26 engaged in general, administrative and business development activities. As of the date of this prospectus, 15 of our employees held advanced degrees. None of our employees are represented by a labor union, and we consider our employee relations to be good.

From time to time, we may be involved in litigation relating to claims arising out of our operations. We are not currently involved in any material legal proceedings.

The following table sets forth certain information about our executive officers, key employees and directors, as of the date of this prospectus.

Robert L. Cavnar has served as our President and Chief Executive Officer and as a director since 2010. He is responsible for our vision, strategy, growth initiatives and clean energy policy. Prior to joining us, from 2005 to 2009, Mr. Cavnar served as President and Chief Executive Officer of Milagro Exploration, a privately held oil and gas exploration company based in Houston, Texas with operations along the Texas, Louisiana and Mississippi Gulf Coast and offshore Gulf of Mexico. Prior to Milagro, from 2002 to 2005, he served as Chairman, President and Chief Executive Officer of Mission Resources where he led the recovery of the company’s financial strength through balance-sheet restructuring and realignment of producing properties. Prior to Mission, Mr. Cavnar held executive positions at El Paso Corporation and led several business unit restructurings. Previously, he was Executive Vice President and Chief Financial Officer of Cornerstone Natural Gas. Mr. Cavnar is a 30 plus year industry veteran with deep experience in operations and management of both public and private energy companies who began his career working on drilling rigs and in field operations, spending 10 years in the field managing multiple rig drilling programs, as well as construction of gas processing facilities. Mr. Cavnar is author of Disaster on the Horizon: High Stakes, High Risks, and the Story Behind the Deepwater Well Blowout. He holds a M.B.A. from the Cox School of Business at Southern Methodist University and a B.S. from Eastern Michigan University, and completed the Program for Management Development at the Harvard Business School. He is Senior Chairman of the board of the Houston Grand Opera, and serves on the board of the Center for National Policy in Washington, D.C. We believe that Mr. Cavnar’s qualifications to serve on our board of directors include his experience as Chief Executive Officer of energy companies and as a business leader as well as his extensive management experience in the energy industry.

Brian J. Cree has served as our Chief Operating Officer since November 2010, where he oversees the operational, financial, administrative and regulatory aspects of the company. He has also served as our Chief Financial Officer since June 2007. Mr. Cree has spent 17 years in the oil and gas industry but also held roles with companies in other industries. Prior to joining us, Mr. Cree served as Vice President of Finance and Chief Financial Officer of ZettaCore, Inc., a start-up molecular memory company, from 2002 to 2007. Before ZettaCore, from 1999 to 2000, Mr. Cree served as Chief Financial Officer and Chief Operating Officer of Wellogix, Inc., an oil and gas software company. Previously, he served as Chief Operating Officer, Executive Vice President and was a director of Patina Oil & Gas Corporation, overseeing its day to day operations and public financial reporting. Mr. Cree helped form Patina in 1996, when it merged with Gerrity Oil & Gas Corporation, where he held several executive positions including Chief Operating Officer, Senior Vice President of Operations, and Chief Accounting Officer, and was also a director. Prior to Gerrity, Mr. Cree was employed by the accounting firm of Deloitte & Touche in Denver, Colorado. He served as Vice Chairman of the Colorado Oil and Gas Conservation Commission, a position appointed by the Governor, from 1999 until 2007. Mr. Cree has a B.A. in Accounting from the University of Northern Iowa.

William R. Mahaffey has served as our Chief Technology Officer since 2009, overseeing scientific research and technology field transfer. From 1995 to 2009, Dr. Mahaffey was the President (Founder) and Chief Technology Officer of Pelorus Environmental and Biotechnology Corporation. Prior to Pelorus, Dr. Mahaffey was Vice President of Research and Biotechnology Applications of Ecova Corporation. As a microbiologist and biochemist, he has 25 years of international experience related to biodegradation and remediation of organic pollutants in the environment. Dr. Mahaffey has served on governmental and industry advisory boards as a recognized expert in the field of bioremediation, chemical oxidation and the in situ application of these technologies for restoration of groundwater. He was an on-scene advisor to the EPA during the Exxon Valdez crisis and consulted with the National Environmental Technologies Application Center at the University of Pittsburgh on development of bioremediation technology screening protocols for post spill response. Dr. Mahaffey has served as an international consultant on in situ bioremediation initiatives for the Swedish National Oil Stockpile Agency, Japan Research Institute, and Japan Environmental Agency. Dr. Mahaffey served as a Technical Advisor to Sandia National Laboratories coordinating the first field scale application of Enhanced In Situ Anaerobic Bioremediation. Throughout his career Dr. Mahaffey has managed major technology research, development and demonstration programs in bioremediation and technology transfer for such entities as Amoco, Condea Vista, Union Pacific Rail Road, Chevron, Unocal, Phillips Petroleum, Gates Rubber, Texaco, Toyota, Ebara and Organo. Dr. Mahaffey received a B.S. and M.S. from the State University of New York, and a Ph.D. in Microbial Biochemistry from The University of Texas.

David M. Austgen has served as our Chief Development Officer since February 2011. With over 23 years of experience in energy and petrochemicals, Mr. Austgen focuses on our mission to create sustainable, long-term gas production resources by establishing strategic partnerships and transactions that will accelerate our growth. Prior to joining us, Mr. Austgen held a variety of positions from 1989 to 2011 at Shell. In his role as Senior Business and JV Manager at Shell Biofuels, Mr. Austgen led teams in commercializing advanced biofuel technologies being developed through partnerships with Iogen Corporation, Virent Energy Systems, and Codexis, among others. He was also responsible for business development in South America. In his prior assignment he was Global Manager, Technology and Operations of Shell Hydrogen. In this assignment, Mr. Austgen represented Shell as a board member in a number of Shell Hydrogen’s joint ventures. Previously, Mr. Austgen led Shell Chemicals’ Strategic Innovation Program, served as an internal strategy consultant for Shell Oil Products US, and managed product development teams in the R&D organization. Mr. Austgen was a Lecturer and Adjunct Professor of Management from 1997 to 2004 at the Jones Graduate School of Management at Rice

University, where he taught courses on the Strategic Management of Innovation and Technology. During 2010, Mr. Austgen served as a consultant to KiOR and American Process Inc., both advanced biofuel companies. He is currently a member of the advisory committees for American Process Inc. and CoolPlanetBiofuels. Mr. Austgen has a B.S. in Chemical Engineering from the University of Notre Dame, and a Ph.D. in Chemical Engineering and a M.B.A., both from The University of Texas.

Michael Sabol has served as our Chief Accounting Officer since May 2011, where he oversees accounting, financial reporting, information technology and risk management aspects of the company. From 2008 to 2011, he was Chief Financial Officer of Range Fuels Inc., a biofuels company based in Colorado developing commercial scale cellulosic biofuels technology. Prior to Range Fuels, Mr. Sabol held various leadership roles in the finance group of multinational telecommunications companies Qwest Communications and Bell Atlantic from 1995 to 2008. From 1993 to 1995, he was the Assistant Controller of Remington Arms Company, a firearms and ammunition company. Prior to Remington, Mr. Sabol was an audit manager at the accounting firm of Price Waterhouse in Philadelphia, Pennsylvania. Mr. Sabol has a B.S. in Accounting and English from King’s College.

Matthew J. Micheli has served as our Corporate Counsel since January 2011 and Secretary since May 2011, where he leads our legal, land, and regulatory efforts. From 2004 to 2011, Mr. Micheli first served as an Associate and then as a Partner of Holland & Hart LLP, a law firm delivering integrated legal solutions, with a focus on trial and dispute resolution and an emphasis on disputes arising from mineral extraction. At Holland & Hart, Mr. Micheli advised oil and gas clients in all areas of mineral extraction and development including Wyoming Split Estate Act compliance, condemnation, surface use agreement negotiations and litigation, and state and federal regulatory compliance. Prior to Holland & Hart, Mr. Micheli worked as an Associate for Hughes & Luce LLP, which was acquired in 2008 by KL Gates LLP. Mr. Micheli has been listed in Chambers USA: America’s Leading Lawyers for Business and in Super Lawyers as a Mountain States Rising Star for Energy & Natural Resources. Mr. Micheli has a B.A. from the University of Wyoming and a J.D. from Brigham Young University’s J. Reuben Clark Law School.

Jeffrey L. Weber has served as our Vice President of Geosciences since 2003 and is responsible for the planning, direction and execution of geosciences in pursuit of our growth and technology objectives. Mr. Weber is a registered Professional Geologist in the State of Wyoming and a Certified Professional Geologist with over 35 years of oil and gas exploration and production experience worldwide in both conventional and unconventional plays. Prior to joining us in 2003, Mr. Weber held the position of Vice President of Exploration with Fidelity Exploration and Production Company beginning in 2000, and with Preston, Reynolds & Co. Inc. beginning in 1996. Upon graduation from Texas A&M University, with a B.S. in Geophysics in 1971, Mr. Weber joined Gulf Oil where, as Regional Geophysicist, he was responsible for Gulf’s exploration efforts in the onshore and offshore Texas Gulf Coast. Between 1978 and 1996, Mr. Weber was engaged in independent geological/geophysical prospect generation and consulting. Mr. Weber is a member of the American Association of Petroleum Geologists, the American Institute of Professional Geologists, and the Rocky Mountain Association of Geologists.

Roland P. DeBruyn has served as our Vice President of Engineering since 2003. In this role, he directs our engineering sciences, which involves the synthesis and integration of advanced petroleum reservoir science with the company’s biologic research. Mr. DeBruyn has 35 years of experience in petroleum and chemical engineering, gained from technical and executive positions with large and small companies prior to working with us. He was a staff engineer and technical supervisor with Dome Petroleum (1976-1984) and Quinoco Petroleum (1984-1988). From 1989 through 1994, he was Vice President and Gulf Coast District Manager with Hallwood Petroleum. He served as Vice President-Engineering with Preston,

Reynolds & Co., Inc. and its affiliated start-up coalbed methane development companies from 1994 through 2000, and then served Fidelity Exploration & Production Company from 2000 through 2003 in the same capacity. Mr. DeBruyn holds a B.S. in Chemical Engineering from the University of Calgary and a M.B.A. from the University of Phoenix. He is a member of the Society of Petroleum Engineers and is registered as a professional engineer in Alberta, Canada.

R. Verlin Dannar has served as our Vice President of Field Operations since 2003 and is responsible for implementation of our restoration and sampling technology as well as the coordination of gathering anaerobic core samples from diverse hydrocarbon fields located both domestically and abroad. From 2000 to 2003, Mr. Dannar was in Project Management for Fidelity Exploration and Production Company. From 1995 to 2000, he was the Operations Manager at Preston, Reynolds & Co., Inc. Previous experience included working with Phillips Petroleum from 1983 to 1993 along with other large and small oil & gas companies. Mr. Dannar has owned and managed companies including Thunder Basin Wireline, Thunder Basin Pumping Service, Thunder Basin Operating, Methane Service Corp, Dannar Minerals, Dannar Farms and Thunder Basin Mechanical. Mr. Dannar has over 31 years of operations management experience in executive management and the field.

Lisa Rice has served as our Vice President of Administration and Human Resources since June 2011, where she oversees administration, human resources, marketing, public relations and communications aspects for us. Prior to joining us, from 2005 to 2011, Ms. Rice oversaw administration and human resources in the financial services arena for Specialized Loan Servicing and Westerra Credit Union. Prior to 2005, Ms. Rice was a human resources leader for several Colorado based companies, including HealthOne and MDC Holdings. Ms. Rice has led the administrative, human resources, public relations and communications functions for several start-up technology firms. Ms. Rice has a B.A. in Sociology from the University of Colorado, an M.A. in Organizational Management from the University of Phoenix, and holds a Senior Professional in Human Resources certification issued by the Society for Human Resources Management.

Eric Szaloczi is our founder and has served as Chairman of the Board since 2003. He also served as our Chief Executive Officer until 2005. Mr. Szaloczi was instrumental in the discovery and development of the coalbed methane industry in the Powder River Basin of Wyoming. During the basin’s development, he came to believe that the gas being produced was created by ongoing biological activity within the coal and was not, as commonly believed, the artifact of ancient geologic processes. These discoveries ultimately led to the inspiration for our formation. As an executive, operator, investor and entrepreneur in the oil and gas industry for over 40 years, Mr. Szaloczi has extensive management experience in all phases of the domestic oil and gas business. He has led exploration, production, transportation and marketing efforts in most producing regions of North America. Mr. Szaloczi has worked as an independent producer and in senior level corporate management positions. Prior to our formation, he was President of Fidelity Exploration & Production Company. He was founder, Director and CEO of Preston, Reynolds & Co., Inc. Mr. Szaloczi is a founder and current Director of the Blue Mountain Foundation, a philanthropic organization supporting a wide variety of charities. We believe that Mr. Szaloczi’s qualifications to serve on our board of directors include being a thought leader in the development of sustainable biogenic gas creation technology and his extensive energy industry experience.

Raymond J. Lane has served as a director since 2008. Mr. Lane has been a Managing Partner at Kleiner Perkins Caufield & Byers, a prominent venture capital firm, since 2000 and currently serves as Chairman of the board of directors of the Hewlett-Packard Company. Mr. Lane was President and Chief Operating Officer of Oracle Corporation, the leading enterprise software and services company. From 1993 to

1997, he also served as the Executive Vice President of Oracle and President of Worldwide Operations. From 1995 to 2000, Mr. Lane served as a Director of Oracle. Prior to joining Oracle, Mr. Lane was a senior partner with Booz-Allen & Hamilton, where he pioneered and led the Information Systems Group. Mr. Lane also served on Booz-Allen’s board of directors and Executive Management Committee. He currently serves on the Board of Governors of West Virginia University. For several years, Mr. Lane has served as Vice Chairman of Special Olympics International and the International Board of Special Olympics. He was elected to the Academy of Distinguished Graduates of West Virginia University and serves on the University’s Foundation Board. Mr. Lane received a bachelor’s degree in mathematics and an honorary Ph.D. in Science from West Virginia University and an honorary Doctorate from Golden Gate University. We believe Mr. Lane’s qualifications to serve on our board of directors are his prominent career as a business leader and extensive experience managing high growth technology companies.

Matthew A. Gibbs has served as a director since December 2008. Mr. Gibbs is a General Partner of Oxford Bioscience Partners, a venture capital firm that has invested over one billion dollars in life science, clean-energy, and healthcare technologies. Mr. Gibbs has 17 years of experience in financing venture backed technology companies. Mr. Gibbs joined Oxford in 1997, became a General Partner in 2005 and leads the clean-energy initiative at Oxford with investments in microbial generated natural gas and biotechnology enhanced oil recovery. He currently serves on the board of directors of Glori Energy and on the boards of directors of several Oxford portfolio companies. Mr. Gibbs was with MedVest, Inc., a venture capital syndicated fund, with Johnson & Johnson Development Corp and Oak Investment Partners, from 1994 to 1996. He received a B.A. from the University of Colorado – Boulder. Mr. Gibbs brings extensive experience in business and the building of companies from early stage to commercial scale to our board of directors.

George Hutchinson has served as a director since 2007. He is a Managing Director and Partner at Jefferies Capital Partners, or JCP, a private equity fund, where he focuses on energy investing across the entire energy value chain. Mr. Hutchinson has 25 years of experience in energy finance and has achieved success on both the buy-side and sell-side. Prior to JCP, Mr. Hutchinson was Senior Managing Director for Jefferies Randall & Dewey, a leading worldwide oil and gas advisor. In 2003, Mr. Hutchinson joined Friedman Billings & Ramsey, or FBR, as Managing Director in the Houston energy office, where he specialized in energy Rule 144A equity placement and led the firm to a leading position in sole managed energy equity underwritings. Prior to FBR, Mr. Hutchinson acted as Managing Director and head of the Houston office for Trust Company of the West. Mr. Hutchinson received his undergraduate degree from Boston University’s School of Management. We believe Mr. Hutchinson’s qualifications to serve on our board of directors include his years of experience in energy finance and transactions, and as a business leader.

Nine directors are authorized under the terms of our bylaws and we currently have five directors.

Upon the consummation of this offering, all of the provisions of our current certificate of incorporation and the stockholder agreement among us, the holders of our preferred stock and certain other of our stockholders regarding the election of directors, will terminate and there will be no further contractual obligations regarding the election of our directors.

Prior to the completion of this offering, we expect to add three additional directors to our board of directors. In accordance with our certificate of incorporation as in effect following the completion of this

offering, our board of directors will be divided into three classes with staggered three-year terms. At each annual meeting of stockholders, the successors to directors whose terms then expire will be elected to serve from the time of election and qualification until the third annual meeting following election. After the completion of this offering, our directors will be divided among the three classes as follows:

Any additional directorships resulting from an increase in the number of directors will be distributed among the three classes so that, as nearly as possible, each class will consist of one-third of the directors. The division of our board of directors into three classes with staggered three-year terms may delay or prevent a change of our management or a change of control at our company.

Our certificate of incorporation will provide that the authorized number of directors may be changed only by resolution of the board of directors. In addition, our certificate of incorporation and bylaws will provide that our directors may be removed only for cause by the affirmative vote of the holders of at least a majority of the votes that all our stockholders would be entitled to cast in an annual election of directors. Any vacancy on our board of directors, including a vacancy resulting from an enlargement of our board of directors, may be filled only by vote of a majority of our directors then in office.

Under Rule 5605 and Rule 5615(b) of The Nasdaq Stock Market, independent directors must comprise a majority of a listed company’s board of directors within one year of listing. In addition, The Nasdaq Stock Market rules require that, subject to specified exceptions, each member of a listed company’s audit, compensation and nominating and governance committees be independent. Audit committee members must also satisfy the independence criteria set forth in Rule 10A-3 under the Securities Exchange Act of 1934, as amended, or the Exchange Act. Under Rule 5605(a)(2) of The Nasdaq Stock Market, a director will only qualify as an “independent director” if, in the opinion of that company’s board of directors, that person does not have a relationship that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director. To be considered to be independent for purposes of Rule 10A-3, a member of an audit committee of a listed company may not, other than in his or her capacity as a member of the audit committee, the board of directors, or any other board committee: (i) accept, directly or indirectly, any consulting, advisory, or other compensatory fee from the listed company or any of its subsidiaries; or (ii) be an affiliated person of the listed company or any of its subsidiaries.

Immediately following the completion of this offering, we expect that at least five members of our board of directors will be “independent” under applicable rules of Rule 5605(a)(2) of The Nasdaq Stock Market.

Our board of directors currently has an audit committee and a compensation committee, and, upon the completion of the offering, will add a nominating and corporate governance committee. The composition

and primary responsibilities of the committees are set forth below. The composition of these committees upon the completion of this offering will satisfy the independence standards for those committees established by the applicable rules and regulations of the SEC and The Nasdaq Stock Market. In addition, upon the completion of this offering, each of these committees will operate under a written charter that satisfies the applicable standards of the SEC and The Nasdaq Stock Market.

The sole member of our audit committee is Mr. Hutchinson and the committee does not currently operate under a written charter. Upon the completion of this offering, the members of our audit committee will be Messrs. , and , each of whom is a non-employee member of our board of directors. will serve as the chairman of the committee. Our board of directors has determined that all members of our audit committee following this offering will meet the requirements for independence and financial literacy under the applicable rules and regulations of the SEC and The Nasdaq Stock Market. Our board of directors has determined that will be our audit committee financial expert, as that term is defined under the applicable rules of the SEC, and has the requisite financial sophistication as defined under the applicable rules and regulations of The Nasdaq Stock Market. Our audit committee will assist our board of directors in overseeing (a) the integrity of our financial statements, (b) our compliance with legal and regulatory requirements, (c) the qualifications and independence of the independent registered public accountants and (d) the performance of our internal auditors (or other personnel responsible for the internal audit function).

The current members of our compensation committee are Messrs. Szaloczi, Gibbs and Lane and the compensation committee does not currently operate under a written charter. Upon the completion of this offering, the members of our compensation committee will be Messrs. , and , each of whom is a non-employee member of our board of directors. will serve as the chairman of the committee. Our board of directors has determined that each of the members of our compensation committee following this offering will be an independent or outside director under the applicable rules and regulations of the SEC, The Nasdaq Stock Market and the Code relating to compensation committee independence. Our compensation committee will provide oversight on the broad range of matters surrounding the compensation of management, including approving the compensation of our Chief Executive Officer, or CEO, and our other executive officers and employees.

Our board of directors does not currently have a nominating and corporate governance committee. Upon the completion of this offering, the members of our nominating and corporate governance committee will be Messrs. , and , each of whom is a non-employee member of our board of directors. will serve as the chairman of the committee. Our board of directors has determined that each of the members of our nominating and corporate governance committee is an independent director under the applicable rules and regulations of the SEC and The Nasdaq Stock Market relating to nominating and corporate governance committee independence. The nominating and corporate governance committee will provide oversight on the broad range of matters surrounding the composition and operation of our board of directors, including identifying individuals qualified to become directors and recommending director nominees.

Our board of directors will adopt a code of business conduct and ethics in connection with this offering. The code will apply to all of our employees, officers (including our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions), directors and consultants. Upon the completion of this offering, the full text of our code of business conduct and ethics will be posted on our website at www.lucatechnologies.com. We expect that any amendments to the code, or any waivers of its requirements, will be disclosed on our website. The inclusion of our website address in this prospectus does not include or incorporate by reference the information on our website into this prospectus.

The current members of our compensation committee are Messrs. Szaloczi, Gibbs and Lane. Mr. Szalocki has previously been one of our officers (but not during 2010) and both Messrs. Gibbs and Lane are affiliated with certain of our significant stockholders which participated in our offerings of Series B preferred stock in September 2007 and March 2008 and our Series C preferred stock in December 2008. For more information, see “Certain relationships and related party transactions.” None of our executive officers currently serves, or in the past year has served, as a member of the board of directors or compensation committee (or other committee serving an equivalent function) of any entity that has one or more executive officers serving on our board of directors or compensation committee.

During 2010, we did not compensate our non-employee directors for their services on our board of directors other than Mr. Hutchinson, who received $1,500 for each meeting of our board of directors which he attended.

The following table sets forth information regarding compensation earned by our non-employee directors during the fiscal year ended December 31, 2010.


Robert G. Reedy		Joseph A. Hall
E. James Cowen		Davis Polk & Wardwell LLP
Porter Hedges LLP		450 Lexington Avenue
1000 Main Street, 36^th Floor		New York, New York 10017
Houston, Texas 77002		Telephone: (212) 450-4000
Telephone: (713) 226-6674		Facsimile: (212) 701-5565
Facsimile: (713) 226-6274


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



Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price(1)	Amount of Registration Fee
Common Stock, $0.001 par value per share	$125,000,000	$14,513


	Per Share	Total
Public offering price	$	$
Underwriting discounts and commissions	$	$
Proceeds, before expenses, to us	$	$


Management			89
Certain relationships and related party transactions			109
Principal stockholders			111
Description of capital stock			114
Shares eligible for future sale			119
Certain United States federal income and estate tax consequences to non-US holders			121
Underwriting			125
Legal matters			133
Experts			133
Where you can find additional information			134
Index to Consolidated Financial Statements			F-1


Conventions that apply to this prospectus			II-2
Prospectus summary			1
Risk factors			12
Special note regarding forward-looking statements			34
Use of proceeds			36
Dividend policy			37
Capitalization			38
Dilution			40
Selected historical consolidated financial data			42
Management’s discussion and analysis of financial condition and results of operations			44
Business			61


	As of March 31, 2011
	Actual			Pro forma		Pro forma, as adjusted
	(in thousands, except share and per share data)
Cash, cash equivalents and investments	$	32,833		$		$

Preferred stock warrant liability		185			—		—

Long-term debt, net of discount (including current portion)		1,064

Convertible preferred stock, $0.001 par value per share; 11,134,559 shares authorized, 11,120,567 shares issued and outstanding, actual; no shares authorized, no shares issued and outstanding, pro forma and pro forma, as adjusted		98,468			—		—
Stockholders’ equity:
Preferred stock, $.001 par value per share; no shares authorized, issued and outstanding, actual; shares authorized, no shares issued and outstanding, pro forma and pro forma, as adjusted		—			—		—
Common stock, $0.001 par value per share; 25,000,000 shares authorized; 8,433,024 issued and outstanding, actual; shares authorized, shares issued and outstanding, pro forma; shares authorized, shares issued and outstanding, pro forma, as adjusted		8
Additional paid-in capital		16,975
Accumulated deficit		(68,104	)

Total stockholders’ equity (deficit)	$	(51,121	)	$		$

Total capitalization	$	48,596		$		$


Assumed initial public offering price per share		$
Pro forma net tangible book value per share at March 31, 2011	$
Increase in pro forma net tangible book value per share attributable to this offering

Pro forma, as adjusted net tangible book value per share after this offering

Dilution per share to new investors		$


	Years ended December 31,						Three months ended March 31,
	2008		2009		2010		2010		2011
Natural gas price (per Mcf)	$	5.57	$	2.94	$	3.83	$	4.49	$	3.68
Natural gas price including commodity contracts (per Mcf)	$	6.83	$	7.86	$	3.83	$	4.49	$	3.68


	Years ended December 31,						Three months ended March 31,
	2008		2009		2010		2010		2011
Sales volumes (MMcf):
Powder River Basin		778.9		486.4		631.7		189.5		68.8

Total natural gas		778.9		486.4		631.7		189.5		68.8


Average production costs (per Mcf) based on sales volumes:
Lease operating expense	$	3.81	$	6.28	$	6.58	$	5.90	$	10.45
Gathering and transportation expense		0.99		1.88		2.27		2.26		3.01
Production taxes		0.54		0.27		0.33		0.38		0.34


Date of Issuance	Number of options		Exercise price per share		Fair value per share
January 18, 2008 to July 23, 2008		238,500	$	3.81	$	3.81
January 23, 2009 to October 8, 2009		471,664		4.12		4.12
January 20, 2010 to October 7, 2010		802,750		5.22		5.22
January 13, 2011 to February 24, 2011		381,000		5.18		5.18


	Three months ended March 31, 2010			Three months ended March 31, 2011			Increase/ (decrease)			% Change
	(unaudited)			(unaudited)
Total operating revenue	$	851		$	253		$	(598	)		(70	)%

Operating expenses:
Research and development expense		1,929			1,359			(570	)		(30	)%
Lease operating expense		1,119			719			(400	)		(36	)%
Gathering and transportation expense		428			207			(221	)		(52	)%
Production taxes		72			23			(49	)		(68	)%
General and administrative expense		1,329			1,739			410			31	%
Depreciation, depletion, and amortization		584			444			(140	)		(24	)%

Total operating expenses		5,461			4,491			(970	)		(18	)%

Operating loss		(4,610	)		(4,238	)		(372	)		(8	)%

Net other expense		(66	)		(31	)		(35	)		(53	)%

Net loss before income taxes		(4,676	)		(4,269	)		(407	)		(9	)%
Provision for income taxes		—			—			—			—

Net loss	$	(4,676	)	$	(4,269	)	$	(407	)		(9	)%


	Year ended December 31, 2009			Year ended December 31, 2010			Increase/ (decrease)			% Change
Total operating revenue	$	3,823		$	2,419		$	(1,404	)		(37	)%

Operating expenses:
Research and development expense		6,832			7,757			925			14	%
Lease operating expense		3,054			4,159			1,105			36	%
Gathering and transportation expense		915			1,437			522			57	%
Production taxes		131			207			76			58	%
General and administrative expense		4,374			5,824			1,450			33	%
Depreciation, depletion, and amortization		3,856			2,607			(1,249	)		(32	)%

Total operating expenses		19,162			21,991			2,829			15	%

Operating loss		(15,339	)		(19,572	)		4,233			28	%

Net other income (expense)		(63	)		(103	)		40			63	%

Net loss before income taxes		(15,402	)		(19,675	)		4,273			28	%
Provision for income taxes		—			—			—			—

Net loss	$	(15,402	)	$	(19,675	)	$	4,273			28	%


	Year ended December 31, 2008			Year ended December 31, 2009			Increase/ (decrease)			% Change
Total operating revenue	$	5,322		$	3,823		$	(1,499	)		(28	)%

Operating expenses:
Research and development expense		5,224			6,832			1,608			31	%
Lease operating expense		2,967			3,054			87			3	%
Gathering and transportation expense		770			915			145			19	%
Production taxes		421			131			(290	)		(69	)%
General and administrative expense		2,610			4,374			1,764			68	%
Depreciation, depletion, and amortization		3,293			3,856			563			17	%

Total operating expenses		15,285			19,162			3,877			25	%

Operating loss		(9,963	)		(15,339	)		5,376			54	%

Net other income (expense)		184			(63	)		(247	)		(134	)%

Net loss before income taxes		(9,779	)		(15,402	)		5,623			58	%
Provision for income taxes		—			—			—			—

Net loss	$	(9,779	)	$	(15,402	)	$	5,623			58	%


Nutrient		Common usage
Vitamins and minerals
Calcium (added as calcium chloride)		Milk
Magnesium (added as magnesium chloride)		Vegetables, cereal
Phosphate (added as magnesium phosphate, phosphoric acid, calcium phosphate, sodium phosphate, potassium phosphate, or sodium tripolyphosphate)		Milk, cheese, meats
Potassium (added as potassium chloride)		Milk, fruits, vegetables
Vitamin B-12, niacin, thiamin, riboflavin, biotin, pantothenic acid, folate		Many foods, human vitamin supplements

Multi-nutrients
Casein hydrolyzates		Special dietary foods as a protein source
Yeast extract, brewer’s yeast, soy protein, peptones		Food flavorings

Cell vitality enhancers
Glycerol		Many prepared foods
Weak organic acids (and sodium, potassium, calcium and magnesium forms)		Formic: fruits, honey; Acetic: vinegar; Propionic: butter, cheese; Butyric: butter, cheese; Lactic: yogurt, cottage cheese; Decanoic: added to coat fruits and vegetables
Glyceryl triacetate		Food additive
Ethyl lactate		Wine, fruits, chicken
Polyoxyethylene		Sweeteners

Tracers
Potassium iodide		Most foods, especially seafood
Sodium chloride		Table salt
Potassium chloride		Substitute for table salt
Sodium bromide		Ionic salt
Potassium bromide		Ionic salt


PRELIMINARY PROSPECTUS		Subject to Completion		June 29, 2011


UBS Investment Bank		Citi		Piper Jaffray


	Natural gas (MMcf)
Proved developed producing		5,524
Proved developed non-producing		—
Proved undeveloped		—

Total proved reserves		5,524


(In thousands)	Proved developed producing		Proved developed non- producing		Proved undeveloped		Total proved
Estimated pre-tax future net cash flows(1)	$	2,497		—		—	$	2,497
Discounted pre-tax future net cash flows (PV-10)(1)	$	1,476		—		—	$	1,476


(In thousands)	Total proved
Estimated pre-tax future net cash flows	$	2,497
10% annual discount		(1,021	)
Discounted pre-tax future net cash flows		1,476
Future income taxes, discounted at 10%		—

Standardized measure of discounted future net cash flows	$	1,476


	Year ended December 31,
	2008		2009		2010
Sales volumes:
*Natural gas volumes (MMcf)*
Powder River Basin		778.9		486.4		631.7

Total natural gas		778.9		486.4		631.7

Average natural gas prices based on sales volumes:
Natural gas price (per Mcf)	$	5.57	$	2.94	$	3.83
Natural gas price including derivative gains (losses)
(per Mcf)		6.83		7.86		3.83
Average production costs (per Mcf) based on sales volumes:
Lease operating expense	$	3.81	$	6.28	$	6.58
Gathering and transportation expense		0.99		1.88		2.27
Production taxes		0.54		0.27		0.33


Year	Non-PRB		PRB		Total
2006		—		91		91
2007		—		32		32
2008		—		148		148
2009		35		142		177
2010		63		8		71
2011 (as of March 31)		12		—		12

Total		110		421		531


	Natural gas
	Gross		Net
Powder River Basin		1,380		1,123

Total		1,380		1,123


	Leasehold acreage
	Developed				Undeveloped
	Gross		Net		Gross		Net
Powder River Basin		78,629		64,595		10,471		10,088

Total		78,629		64,595		10,471		10,088


	Acres expiring
Twelve months ending:	Gross		Net
December 31, 2011		314		314
December 31, 2012		361		361
December 31, 2013		6,288		6,288
December 31, 2014		—		—
December 31, 2015		—		—

Total		6,964		6,964


Name	Age		Position(s)
Robert L. Cavnar		58	President, Chief Executive Officer and Director
Brian J. Cree		48	Chief Operating Officer and Chief Financial Officer
William R. Mahaffey, Ph.D.		57	Chief Technology Officer
David M. Austgen, Ph.D.		52	Chief Development Officer
Michael Sabol		45	Chief Accounting Officer
Matthew J. Micheli		35	Corporate Counsel and Secretary
Jeffrey L. Weber		61	Vice President of Geosciences
Roland P. DeBruyn		57	Vice President of Engineering
R. Verlin Dannar		55	Vice President of Field Operations
Lisa Rice		45	Vice President of Administration and Human Resources
Eric Szaloczi (1)		62	Founder and Chairman of the Board of Directors
Raymond J. Lane (1)		64	Director
Matthew A. Gibbs (1)		42	Director
George Hutchinson (2)		54	Director


Name	Fees earned or paid in cash ($)		Stock awards ($)		Option awards ($)		Non-equity incentive plan compensation ($)		Change in pension value and nonqualified deferred compensation earnings ($)		All other compensation ($)			Total ($)
Eric Szaloczi		—		—		—		—		—	$	10,483	(1)	$	10,483
Raymond J. Lane		—		—		—		—		—		—			—
Matthew A. Gibbs		—		—		—		—		—		—			—
Dr. Josef R. Wünsch(2)		—		—		—		—		—		—			—
George Hutchinson	$	4,500