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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2013

or

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

For the transition period from                     to                     

Commission file number 001-32960

GeoMet, Inc.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code

(713) 659-3855

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o  No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o  No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x  No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

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. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o  No x

The aggregate market value of common stock, par value $0.001 per share, held by non-affiliates (based upon the closing sales price of $0.16 on the NASDAQ Capital Market on June 28, 2013) on the last business day of registrant’s most recently completed second fiscal quarter was approximately $4.1 million.

As of March 1, 2014, 40,652,317 shares and 6,000,571 shares, respectively, of the registrant’s common stock, par value $0.001 per share, and preferred stock, par value $0.001 per share, were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

An amendment to this Annual Report on Form 10-K, to be filed with the Securities and Exchange Commission not later than 120 days after the close of the Registrant’s fiscal year, is incorporated by reference under Part III of this Form 10-K.

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GeoMet, Inc.

Form 10-K

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CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

Included in this annual report are certain forward-looking statements, within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical facts, included in this annual report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including statements regarding our reserve quantities and the present value thereof, planned capital expenditures, increases in natural gas production, the number of anticipated wells to be drilled, future cash flows and borrowings, our financial position, business strategy and other plans and objectives for future operations. We use the words “may,” “will,” “expect,” “anticipate,” “estimate,” “believe,” “continue,” “intend,” “plan,” “budget” and other similar words to identify forward-looking statements. You should read statements that contain these words carefully and should not place undue reliance on these statements. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

·                  oversupply of natural gas in the US markets, which depresses the price we receive for our natural gas production;

·                  declines in the prices we receive for our natural gas affecting our operating results, cash flows and credit capacity;

·                  general international and domestic economic conditions that may be less favorable than expected;

·                  changes in our business strategy;

·                  our financial position, including our cash flow and liquidity;

·                  the effects of our indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to our competitors that have less debt, and could have other adverse consequences;

·                  volatility in the international and domestic capital and credit markets, including fluctuations in interest rates and availability of capital;

·                  uncertainties in estimating our natural gas reserves;

·                  our ability to replace our natural gas reserves;

·                  uncertainties in exploring for and producing natural gas;

·                  new natural gas development projects and exploration for natural gas in areas where we have little or no proven natural gas reserves;

·                  our ability to acquire water supplies needed for drilling, or our ability to dispose of water used or removed from strata at a reasonable cost and within applicable environmental rules;

·                  other persons could have ownership rights in our advanced natural gas extraction techniques which could force us to cease using those techniques or pay royalties;

·                  availability of drilling and production equipment and field service providers;

·                  disruptions, capacity constraints in, or other limitations on the pipeline systems that deliver our natural gas;

·                  our need to use unproven technologies to extract coalbed methane in some properties;

·                  our ability to retain key members of our senior management and key technical employees;

·                  the outcomes of legal proceedings in which we may become involved;

·                  the possibility that the industry may be subject to future regulatory or legislative actions (including changes to existing tax rules and regulations and changes in environmental regulation);

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·                  the effects of government regulation and permitting and other legal requirements;

·                  the potential sale of all or substantially all of our assets;

·                  other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors may negatively impact our businesses, operations or pricing; and

·                  our ability to operate effectively in a state or jurisdiction where land ownership and coalbed methane rights are complicated or unresolved.

Other factors which could affect the events discussed in our forward looking statements are described under “Item 1A. Risk Factors” in this annual report. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this annual report. All forward-looking statements speak only as of the date of this annual report. Other than as required under securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

All references in this annual report to the “Company,” “GeoMet,” “we,” “us” or “our” are to GeoMet, Inc. and our wholly owned subsidiaries. Unless otherwise noted, all information in this annual report relating to natural gas reserves and the estimated future net cash flows attributable to those reserves is based on estimates prepared by independent engineers and is net to our ownership interest.

GLOSSARY OF NATURAL GAS AND COALBED METHANE TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used in this document.

Bcf. Billion cubic feet of natural gas.

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

CBM. Coalbed methane.

CBM acres. Acreage under a lease that excludes oil, natural gas, and all other minerals other than CBM.

Coal seam. A single layer or stratum of coal.

Completion. The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Estimated proved reserves. Defined in Rule 4-10 of Regulation S-X under the Securities Act as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Estimated proved undeveloped reserves. Estimated proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

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Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gas desorption test. A process to estimate the volume of natural gas adsorbed in a volume of coal (usually expressed as cubic feet per ton) by placing a sample of coal into a sealed canister and taking periodic measurements of gas desorbed, temperature and pressure for up to 90 days. The estimate of total gas adsorbed in the coal sample is the sum of: (i) the measurements of natural gas during the test period, corrected to standard temperature and pressure (the “measured natural gas”), (ii) the “lost natural gas,” which is calculated using the elapsed time the sample desorbed before its placement into the canister and the rate of desorption determined from the test period, and (iii) the “remaining natural gas,” which is determined by measuring the natural gas released while grinding the coal sample into a powder or which is calculated mathematically using the measurements from the test period.

Gathering system. Pipelines and other equipment used to move natural gas from the wellhead to the trunk or the main transmission lines of a pipeline system.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Henry hub. The Henry hub is a distribution hub on the natural gas pipeline system in Erath, Louisiana. Due to its importance, it lends its name to the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange (NYMEX).

Mcf. Thousand cubic feet of natural gas.

MMBtu. Million British thermal units.

MMcf. Million cubic feet of natural gas.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be.

Net revenue interest. An owner’s interest in the revenues of a well.

NYMEX. The New York Mercantile Exchange.

Overriding royalty interest. A fractional, undivided interest that is carved out of a working interest with the right to participate or receive proceeds from the sale of oil or natural gas.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Shale. A well hardened, very fine to fine grained sedimentary rock. Shale has ultra-low permeability and is formed from the compaction of silt, clay, or mud. Many shales contain a mixture of organic compounds called kerogen, which liberates natural gas during the maturation process of the shale. Gas within the shale can be stored onto the molecular surface of insoluble organic matter, trapped within the rock’s pore space or present within open fractures.

Shut-in. An oil or natural gas well which has been stopped from producing.

Standardized measure. An estimate of the present value of the future net revenues from estimated proved natural gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs, operating expenses, and any estimates of federal income taxes. The estimated future net revenues are discounted at an annual rate of 10% in accordance with the practice of the SEC, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the date indicated and held constant for the life of the reserves.

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Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas regardless of whether or not such acreage contains estimated proved reserves.

Working interest. The operating or cost-bearing interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

PART I

Items 1 and 2. Business and Properties

Overview

GeoMet is primarily engaged in the exploration for and development and production of natural gas from coal seams (“coalbed methane” or “CBM”). All of our production is CBM, which is a dry natural gas containing no hydrocarbon liquids.  GeoMet was incorporated under the laws of the state of Delaware on November 9, 2000. We were originally founded as a consulting company to the coalbed methane industry in 1985 and have been active as an operator, developer and producer of coalbed methane properties since 1993.  Our operations are concentrated in the central Appalachian Basin in Virginia and West Virginia.

The natural gas industry is capital intensive.  Natural gas markets traditionally have been highly volatile.  We have historically made substantial capital expenditures in the exploration, development and acquisition of natural gas reserves.  Our capital expenditures have been financed primarily with internally generated cash flows from operations, bank borrowing and equity raises.

Developments in 2013

Natural gas prices in 2012 were depressed compared with prices generally prevailing during prior years and historically low natural gas prices have continued in 2013.  The low natural gas prices in 2012 and 2013 had pervasive adverse consequences to our business, including a borrowing base deficiency under our credit agreement. On August 8, 2012, we amended our credit agreement to include a conforming tranche equal to the borrowing base, and a non-conforming tranche in the amount of outstanding loans in excess of the borrowing base. The amendment required that we use nearly all of our excess cash flows to reduce outstanding borrowings under our credit agreement and significantly limited our capital expenditures.

In February 2013, we engaged Lantana Oil & Gas Partners (“Lantana”) to assist us in connection with the sale of our assets in the Black Warrior Basin of Alabama. On June 14, 2013, we closed the sale of the Alabama properties and used approximately $57.0 million of the proceeds to repay outstanding borrowings under our credit agreement. After this repayment, borrowings outstanding under our credit agreement totaled $77 million. In connection with this repayment the non-conforming portion of borrowings was repaid and we no longer have a borrowing base deficiency under our credit agreement. As of December 31, 2013, the interest rates applied to our borrowings was 3.24%.  At that time, our credit agreement had a maturity date of April 1, 2014.

In September 2013, our board of directors requested that FBR Capital Markets & Co. (“FBRC”) solicit indications of interest from third parties regarding a potential acquisition of GeoMet. Our board of directors did not find any of the proposals it received as a result of that process sufficiently attractive to pursue at that time.  In November 2013, we concluded that process, and engaged Lantana to assist us in pursuing the sale of all or substantially all of our assets.  In November 2013, we amended the terms of our engagement of FBRC to terminate FBRC’s services as our financial advisor in connection with a potential transaction except and to the extent we requested that FBRC render an opinion with respect to the fairness of the consideration to be received in connection with a proposed transaction. In addition to any fees payable to FBRC in connection with such opinion, FBRC remained entitled to certain fees in the event we consummated a transaction with certain third parties.

Recent Developments

On February 13, 2014, the Company and its wholly-owned subsidiaries, GeoMet Operating Company, Inc. and GeoMet Gathering Company, LLC (collectively as a group, the “Sellers”), entered into an asset purchase agreement (the “Asset Purchase Agreement”) to sell substantially all of the Company’s remaining assets, comprising coalbed methane interests and other assets (collectively, the “Assets”) located in the Appalachian Basin in McDowell, Harrison, Wyoming, Raleigh, Barbour and Taylor Counties, West Virginia and Buchanan County, Virginia (the “Asset Sale”) to ARP Mountaineer Productions, LLC, a Delaware limited liability company (the “Buyer”) and a wholly-owned subsidiary of Atlas Resource Partners, L.P., a Delaware limited partnership (“Atlas”), for a purchase price of $107 million, subject to various purchase price adjustments.  Atlas has provided an irrevocable guaranty of ARP Mountaineer’s performance of its obligations under the Asset Purchase Agreement.  The effective date of the Asset Sale is January 1, 2014, and it is expected to close in the second quarter of 2014 subject to the satisfaction of certain closing

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conditions, which includes obtaining the approval of the holders of (i) at least fifty percent (50%) of the outstanding shares of GeoMet’s Series A Convertible Redeemable Preferred Stock, par value $0.001 (the “Preferred Stock”), entitled to vote at a special meeting of the stockholders of GeoMet and (ii) a majority of the outstanding shares of GeoMet’s common stock, par value $0.001 (the “Common Stock”) including the outstanding shares of Preferred Stock on an as-converted basis voting together with the holders of Common Stock as a single class.

On February 13, 2014, at the meeting of the GeoMet board of directors to consider and approve the Asset Purchase Agreement, FBRC rendered its opinion to the GeoMet board of directors as to, as of February 13, 2014, the fairness, from a financial point of view, to GeoMet of the consideration of $107 million to be received by GeoMet for the Assets, subject to the assumed liabilities, in the Asset Sale pursuant to the Asset Purchase Agreement.

The Asset Purchase Agreement contains customary representations and warranties of the parties and covenants of the Sellers. The Asset Purchase Agreement also provides for the parties to indemnify each other with respect to certain matters, subject to certain limitations on time and amount.

The Asset Purchase Agreement includes certain termination rights, including, among others, the right of (i) the Buyer to terminate if GeoMet’s board of directors makes a change in recommendation regarding the Asset Sale, (ii) the Company to terminate if GeoMet’s board of directors elects to pursue a superior proposal, or (iii) either the Buyer or GeoMet to terminate if GeoMet’s stockholders do not approve the Asset Sale. Under certain circumstances, the termination of the Asset Purchase Agreement will result in the payment of a termination fee to the Buyer.

The final net proceeds will be reduced after accounting for the cash flows from the effective date to the closing date. The Company plans to use the cash proceeds to liquidate all of its outstanding liabilities, including repaying the outstanding balance under its credit agreement.  The Company expects the proceeds from the Asset Sale to exceed the Company’s liabilities and any such excess amount shall be used to make severance, retention and change of control payments to certain employees and members of the Company’s senior management and for normal working capital and operating expense purposes as the Company continues to evaluate strategic alternatives.

Assuming the Asset Sale closes at the end of the second quarter of 2014, the Company currently estimates that the purchase price will be adjusted downward approximately $7 million to account for cash flows from the effective date to closing, that the outstanding balance of its credit agreement will be approximately $66 million, and that the Company’s other liabilities (including federal income taxes and hedge termination costs (which could vary substantially given volatility in prevailing natural gas prices)) will total approximately $4 million.  The excess net proceeds will also be used to pay the Company’s transaction costs and expenses (currently estimated to total approximately $3 million), and to make severance, retention and change of control payments to certain employees and members of the Company’s senior management (currently estimated to total approximately $4 million).

Assuming, for these purposes only, that the foregoing estimates are accurate, we currently estimate that the remaining balance of the net proceeds would total approximately $23 million.

The remaining balance of the net proceeds will be used for normal working capital and operating expense purposes while the Company evaluates its next steps. We currently anticipate that the Asset Sale would be followed by either a merger or a dissolution and distribution of our remaining assets in accordance with applicable law.

The terms of our outstanding Preferred Stock provide that in the event of a liquidation or dissolution of the Company, the holders of our Preferred Stock would be entitled to a liquidation preference before the holders of our Common Stock would be entitled to receive any distributions from the Company.  The liquidation preference is equal to the original investment amount of the Preferred Stock ($40 million) plus paid-in-kind shares plus accrued and unpaid dividends, and currently totals approximately $60 million.  Therefore, if the Company is dissolved following the Asset Sale, the estimated remaining net proceeds (approximately $23 million) would be less than the liquidation preference to which the holders of our Preferred Stock are currently entitled ($60 million).  Absent a concession from the holders of our Preferred Stock, the holders of our Common Stock would not receive any distributions as a result of the Asset Sale or subsequent dissolution of the Company.

In connection with the execution of the Asset Purchase Agreement, certain of our stockholders entered into a voting agreement with the Buyer pursuant to which, subject to certain exceptions, they have agreed to vote their shares in favor of the Asset Sale.  Such stockholders included Sherwood Energy, LLC, who is the largest holder of our outstanding shares of Preferred Stock and currently owns approximately 58.6% of our Preferred Stock, Yorktown Energy Partners IV, L.P., who is the largest holder of our outstanding shares of Common Stock and currently owns approximately 30.6% of our Common Stock, and all of the members of our board of directors and our senior management. Collectively, these stockholders own approximately 48.9% of the combined voting power of our Common Stock and Preferred Stock (on an as-converted basis) treated as a single class and approximately 59.6% of our Preferred Stock voting power.

Approval of the Asset Sale will be submitted to our stockholders for their consideration, and, on March 27, 2014, the Company filed with the SEC a definitive proxy statement on Schedule 14A to be used to solicit stockholder approval of the transaction.

On February 28, 2014, we amended our credit agreement to extend the maturity date from April 1, 2014 to the earliest to occur of: (i) June 30, 2014, (ii) the closing of the Asset Sale pursuant to the Asset Purchase Agreement, or the sale of the Assets pursuant to a substitute purchase agreement, or (iii) the termination of the Asset Purchase Agreement or any substitute purchase agreement, in order to allow a reasonable time to properly close the Asset Sale.  In connection with this amendment, we paid the bank group a fee of $133,125.

Our board of directors intends to continue to evaluate other strategic alternatives if the Asset Sale is approved by our stockholders.  We currently anticipate that the Asset Sale would be followed by either a merger or a dissolution and distribution of our remaining assets in accordance with applicable law.

Characteristics of Coalbed Methane and Non-Conventional Shallow Gas

The source rock in conventional natural gas is usually different from the reservoir rock, while in coalbed methane the coal seam serves as both the source rock and the reservoir rock. The storage mechanism in conventional natural gas is also different as gas is stored in the pore or void space of the rock in conventional natural gas, but in coalbed methane, most, and frequently all, of the gas is stored by adsorption. Adsorption allows large quantities of gas to be stored at relatively low pressures. A unique characteristic of coalbed methane is that the gas flow can be increased by reducing the reservoir pressure. Frequently the coalbed pore space, which is in the form of cleats or fractures, is filled with water. The reservoir pressure is reduced by pumping out the water and releasing the methane from the molecular structure, which allows the methane to flow through the cleat structure to the well bore. While a conventional natural gas well typically decreases in flow as the reservoir pressure is drawn down, a coalbed methane well, after desorption pressure has been achieved, will typically increase in production for up to five years from achievement of desorption pressure depending on well spacing. In some cases, achievement of desorption pressure may take an extended period of time.

Coalbed methane and conventional natural gas both have methane as their major component. While conventional natural gas often has more complex hydrocarbon gases, coalbed methane rarely has more than 2% of the more complex hydrocarbons. In the eastern coal fields of the United States, coalbed methane is generally comprised of 98% to 99% pure methane and requires only dehydration of the gas to remove moisture to achieve pipeline quality. In the western coal fields of the United States, it is also sometimes necessary to strip out either carbon dioxide or nitrogen. Once coalbed methane has been produced, it is gathered, transported, marketed, and priced in the same manner as conventional natural gas.

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The content of gas within a coal seam is measured through gas desorption testing. The ability to flow gas and water to the well bore in a coalbed methane well is determined by the fracture or cleat network in the coal. At shallow depths of less than 500 feet, these fractures often open enough to produce the fluids naturally. At greater depths the networks are progressively squeezed shut, reducing the ability to flow. It is necessary to provide other avenues of flow such as hydraulically fracturing the coal seam. By pumping fluids at high pressure, fractures are opened in the coal and a slurry of fluid and sand proppant is pumped into the fractures so that the fractures remain open after the release of pressure, thereby enhancing the flow of both water and gas to allow the economic production of gas.

Areas of Operation

Our core areas of operations are in the Central Appalachian Basin of Virginia and West Virginia. The Central Appalachian Basin is a mountainous region where coal mining is prevalent. We previously had operations located in the Black Warrior and Cahaba Basins in Alabama. On June 14, 2013, the Company closed the sale of all of its coalbed methane properties located in Alabama.

Central Appalachia

Pond Creek and Lasher Fields—We are the operator of 298 producing vertical CBM wells in which we own a 99.0% average working interest in the Pond Creek and Lasher fields located in southern West Virginia and southwestern Virginia. At December 31, 2013, approximately 91% of our estimated proved developed reserves, or 92.5 Bcf, is in the Pond Creek field. Net daily sales of gas averaged 15.4 MMcf per day for 2013. Our natural gas production from the Pond Creek field is delivered into the Jewell Ridge pipeline system owned by East Tennessee Natural Gas, LLC (“ETNG”). We have two long-term transportation agreements with ETNG which went into effect in April 2007 with total maximum daily quantities of 15,000 MMBtu’s and 10,000 MMBtu’s and primary terms of 15 years and 10 years, respectively. Our gas from the Lasher field is delivered into the Columbia Gas Transmission pipeline with firm transportation for 500 MMBtu’s per day. We also own and operate a 12 mile, 8 inch high-pressure steel pipeline and gas treatment and compression facilities through which the Pond Creek field natural gas production is gathered, dehydrated, and compressed for delivery into the Jewell Ridge Lateral of the East Tennessee pipeline system. In addition, we own and operate a disposal well to dispose of produced water from both the Pond Creek and Lasher fields.

Pinnate Horizontal Wells—We are the operator of 44 producing pinnate horizontal CBM wells in which we own a 71.6% average working interest in central and northern West Virginia. We also have a 33.7 % average working interest in 67 non-operated pinnate horizontal wells in central West Virginia. At December 31, 2013, approximately 6% of our estimated proved developed reserves, or 6.1 Bcf, is associated with these pinnate horizontal wells. Net daily sales of natural gas averaged 7.6 MMcf per day for 2013.  We are party to two firm transportation agreements with total maximum daily capacity of 18,500 MMBtu per day and primary terms expiring from April 2013 through November 2024 which can be automatically extended at GeoMet’s option at the maximum tariff rate. We are also party to a 10,000 MMBtu per day gathering contract that is currently in a month-to-month evergreen term.  In some cases, our natural gas sales volumes are delivered to market under transportation agreements controlled by our working interest partners. Generally, our natural gas sales volumes are sold at a delivery point into the respective interstate pipeline system utilized.

Alabama

On June 14, 2013, the Company closed the sale of all of its coalbed methane properties located in Alabama. Net daily sales of natural gas from our Alabama properties averaged 9.7 MMcf per day through June 14, 2013.

Estimated Proved Reserves

Estimated proved natural gas reserves as of December 31, 2013, as estimated by Prator Bett, L.L.C. (“Prator Bett”), independent petroleum engineers, totaled approximately 102 Bcf. Estimated proved natural gas reserves as of December 31, 2012, as estimated by DeGolyer and MacNaughton (“D&M”) and Ryder Scott Company, L.P. (“Ryder Scott”), independent petroleum engineers, totaled approximately 137 Bcf. The present value of future net cash flows attributable to proved reserves, discounted at 10%, was approximately $66.3 million at December 31, 2013. The present value of future net cash flows attributable to proved reserves, discounted at 10%, was approximately $72.9 million at December 31, 2012. A price of $3.75 per Mcf was used at December 31, 2013 compared to $2.91 per Mcf at December 31, 2012. Our estimated proved reserves at December 31, 2013 are 100% coalbed methane and 100% proved developed.

The following table presents information related to our estimated proved reserves as of December 31, 2013:

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There are no PUD reserves at December 31, 2013 and 2012 included in our proved reserves at year end.

CBM-producing natural gas reservoirs generally are characterized by an initial period of incline followed by an extended period of declining production rates that vary depending upon reservoir characteristics and other factors. Therefore, without reserve additions in excess of production through successful exploration and development activities or acquisitions, our reserves and production will decline. Such decline rate, however, is lower than what is generally experienced with non-CBM wells. See “Risk Factors” for a discussion of the risks inherent in CBM gas estimates and for certain additional information concerning the estimated proved reserves.

Our policies and procedures regarding internal controls over the recording of our oil and natural gas reserves is structured to objectively and accurately estimate our oil and natural gas reserves quantities and present values in compliance with both accounting principles generally accepted in the United States and the SEC’s regulations.

Our controls over reserve estimates included retaining Prator Bett as our independent petroleum engineers. We provided information about our oil and natural gas properties, including production profiles, prices and costs, to Prator Bett and they prepared their own estimates of our oil and natural gas reserves attributable to our properties. All of the information regarding reserves in this annual report on Form 10-K is derived from the report of Prator Bett, which are included as an exhibit to this annual report on Form 10-K. The technical persons at Prator Bett that are responsible for preparing the reserve estimates are independent petroleum engineers and geoscientists that meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our controls also include oversight of our reserves estimation process by our Board of Directors. Both our Chief Executive Officer and Chief Financial Officer are charged with the responsibility of reviewing and approving the natural gas reserve estimates prepared by Prator Bett.

Natural gas reserve engineering requires subjective estimates of underground accumulations of natural gas and assumptions concerning future natural gas prices, production levels, and operating and development costs. Coalbed methane-producing natural gas reservoirs generally are characterized by an initial period of inclining production rates as pressure in the reservoir decreases, followed by declining production rates that vary depending upon reservoir characteristics and other factors. These decline rates, however, are commonly lower than what is generally experienced with non-coalbed methane wells and the life of coalbed methane wells are generally longer lived than conventional natural gas wells.

The reserves information in this annual report on Form 10-K represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced. For additional information regarding estimates of proved reserves, the preparation of such estimates by Prator Bett and other information about our natural gas reserves, see Supplementary Financial and Operating Information on Gas Exploration, Development and Producing Activities (Unaudited) included elsewhere in this annual report on Form 10-K.

Production and Operating Statistics

The following table presents certain information with respect to production and operating data for the years ended December 31:

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(1)                  Decreased production is due to the Alabama properties sold in June 2013.

(2)                  Average realized price includes the effects of realized gains and losses on derivative contracts.

(3)                  Increased expenses per Mcf are the result of reduced production due to the Alabama properties sold in June 2013.

Productive Wells and Acreage

The following table sets forth our interest in undeveloped acreage, developed acreage and productive wells in which we owned a working interest as of December 31, 2013. Gross represents the total number of acres or wells in which we owned a working interest. Net represents our proportionate working interest resulting from our ownership in the gross acres or wells. Productive wells are wells in which we have a working interest and that are producing or capable of producing natural gas.

The following table sets forth our interest in undeveloped acreage, developed acreage and productive wells in which we owned a working interest as of December 31, 2013:

Our material undeveloped leases are in the Pond Creek, Triangle, and Crab Orchard fields of the Central Appalachian Basin. Generally, the undeveloped acreage expires on various dates from 2014 through 2015. The terms of the undeveloped acreage may be extended by drilling and production operations or through negotiation with lessors. However, we have no current plans in place to develop any of our lease acreage or to negotiate extensions of these leases.

Drilling Activity

There have been no exploratory or development wells completed in the last two fiscal years. Additionally, no drilling is currently scheduled for 2014.

Title to Properties

Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business.

We believe that we have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, we make minimal investigation of title at the time we acquire undeveloped properties. We make title investigations and receive title opinions of local counsel only before we commence drilling operations. We believe that we have satisfactory title to all of our other assets. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with our use in the operation of our business.

Insurance

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies that include coverage for general liability (includes sudden and accidental pollution), physical damage to certain of our natural gas assets, auto liability, worker’s compensation and employer’s liability, among other things. At the depths and in the areas in which we operate we typically do not encounter high pressures or extreme drilling conditions. Accordingly, we do not carry control of well insurance.

Currently, we have general liability insurance coverage up to $2 million per occurrence, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties arising from our operations. Our insurance policies contain maximum policy limits and in most cases, deductibles, generally less than $25,000 per occurrence. Our insurance policies are subject to certain customary exclusions and limitations. In addition, we maintain $15 million in excess liability coverage, which increases coverage limits if the general liability, auto or employers liability policy limit is reached. Our property and casualty lines of coverage expire annually in September.

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We attempt to have our third-party contractors, including those that perform hydraulic fracturing operations for us, sign master service agreements in which each party agrees to indemnify the other party against personal injury and property damage claims for which they had no responsibility.

We evaluate the need and availability of insurance, coverage limits and deductibles as circumstances warrant. Future insurance coverage for the oil and gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.

Bonding

Companies engaged in oil and gas operations are generally required by regulatory authorities and other parties to post bonds in connection with their operations. These bonds provide a guarantee to the holder of the bond that the company will perform as required under the terms of the agreement requiring such bond. As of March 1, 2014, the Company had approximately $900,000 bonds issued on its behalf. If we fail to perform under the terms any agreement requiring such bond, the bond holder may demand that the surety make payments or provide services under the bond. We must reimburse the sureties for any expenses or outlays they incur on our behalf. To date, we have not been required to make any reimbursements to our sureties for bond-related costs.

As is common in the surety industry, sureties issue bonds on an individual basis and can decline to issue bonds at any time. Our relationship with our surety has, to date, allowed us to provide surety bonds as required. However, current market conditions, as well as changes in our surety’s assessment of our operating and financial risk, could cause our surety to decline to issue bonds for our work. The indemnity agreement we have executed with our surety also permits them, at any time, to require the Company provide collateral to secure the Company’s obligations to the surety. The Company, to date, has not received any such requests for collateral.

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil and natural gas companies in acquiring properties, contracting for drilling and other services and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit. We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program. Competition is also strong for attractive natural gas producing properties, undeveloped leases and drilling rights, and there can be no assurances that we will be able to compete satisfactorily when attempting to make further acquisitions.

Principal Customers and Marketing Arrangements

The market for our natural gas production depends on factors beyond our control, including the amount of domestic production of natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand for natural gas, weather conditions, the marketing of competitive fuels and the effect of state and federal regulation. The natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Five purchasers of our natural gas production purchased 99.1% of the gas we delivered to market during the year ended December 31, 2013, of which 62.0% was purchased by one entity. The loss of any one of our significant natural gas purchasers could materially adversely affect our financial condition and results of operations.  However, we believe other purchasers are available in our area of operations. As of December 31, 2013, three of our natural gas purchasers and one joint interest owners accounted for 88% of our accounts receivable related to gas sales, of which one natural gas purchaser accounted for 65% of our accounts receivable related to gas sales.

Seasonality of Business

Weather conditions can affect the demand for natural gas and can also delay drilling activities, disrupting our business operations. Historically, demand for natural gas has been higher in the fourth and first quarters, which has traditionally resulted in higher natural gas prices. However, we believe that the recent over-supply in the natural gas market has diminished this seasonal fluctuation. Still, due to these potential seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

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Governmental, State and Local Regulations

Our coalbed methane exploration and production operations are subject to significant federal, state, and local laws and regulations governing the gathering and transportation of our gas production across state and federal boundaries. The following is a summary of the material existing regulations to which our operations are subject.

Regulation by the Federal Energy Regulatory Commission (“FERC”) of Interstate Natural Gas Pipelines. We do not own any interstate natural gas pipelines, so the Federal Energy Regulatory Commission, or the FERC, does not directly regulate any of our operations. However, the FERC’s regulation influences certain aspects of our business and the market for our products. In general, the FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce, and its authority to regulate those services includes:

·                  the certification and construction of new facilities;

·                  the extension or abandonment of services and facilities;

·                  the maintenance of accounts and records;

·                  the acquisition and disposition of facilities;

·                  the initiation and discontinuation of services; and

·                  various other matters.

In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.

Gathering Pipeline Regulation. Section 1(b) of the Natural Gas Act exempts natural gas gathering facilities from the jurisdiction of the FERC. We own interstate and intrastate natural gas gathering lines that we believe would meet the traditional tests the FERC has used to establish a pipeline’s status as a gatherer not subject to the FERC’s jurisdiction. However, the distinction between the FERC-regulated transmission services and federally unregulated gathering services is the subject of regular litigation. In such a circumstance, the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by the FERC and the courts.

In the states in which we operate, regulation of intrastate gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirement and complaint based rate regulation. For example, we are subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. In certain circumstances, such laws will apply even to gatherers like us that do not provide third party, fee-based gathering service and may require us to provide such third party service at a regulated rate. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.

Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Sales of Natural Gas. The price at which we sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. Our natural gas sales are affected by the availability, terms, and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The stated purpose of many of these regulatory programs is to promote competition among the various sectors of the natural gas industry, and generally reflect light handed regulation. We cannot predict the ultimate impact of regulatory initiatives to our natural gas operations.

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We do not believe that we will be affected by any such FERC action materially differently than other sellers of natural gas with whom we compete.

Virginia Regulation. The Virginia Supreme Court has stated that the grant of coal rights only does not include rights to coalbed methane absent an express grant of coalbed methane, natural gases, or minerals in general. The situation may be different if there is any expression in the severance deed indicating more than mere coal is conveyed. Virginia courts have also found that the owner of the coalbed methane did not have the right to fracture the coal in order to retrieve the coalbed methane and that the coal operator had the right to ventilate the coalbed methane in the course of mining. In Virginia, we believe that we own the relevant property rights in order to capture gas from the vast majority of our producing properties. In addition, Virginia has established the Virginia Gas and Oil Board and a procedure for the development of coalbed methane by an operator in those instances where the owner of the coalbed methane has not leased it to the operator or in situations where there are conflicting claims of ownership of the coalbed methane. The general practice is to force pool both the coal owner and the gas owner. In those instances, any royalties otherwise payable are paid into escrow and the burden then is upon the conflicting claimants to establish ownership by court action. The Virginia Gas and Oil Board does not make ownership decisions.

West Virginia Regulation. West Virginia’s Supreme Court has held that, in a conventional oil and gas lease executed prior to the inception of widespread public knowledge regarding coalbed methane operations, the oil and gas lessee did not acquire the right to produce coalbed methane. As of December 31, 2013, the West Virginia courts have not clarified who owns coalbed methane in West Virginia. Therefore, the ownership of coalbed methane is an open question in West Virginia. West Virginia has enacted a law, the Coalbed Methane Wells and Units Article of the Environmental Resources Act (the “West Virginia Act”), regulating the commercial recovery and marketing of coalbed methane. Although the West Virginia Act does not specify who owns, or has the right to exploit, coalbed methane in West Virginia and instead refers ownership disputes to judicial resolution, it contains provisions similar to Virginia’s pooling law. Under the pooling provisions of the West Virginia Act, an applicant who proposes to drill is permitted to prosecute an administrative proceeding with the West Virginia Coalbed Methane Review Board to obtain authority to produce coalbed methane from pooled acreage. Owners and claimants of coalbed methane interests who have not consented to the drilling are afforded certain elective forms of participation in the drilling (e.g., royalty or owner) but their consent is not required to obtain a pooling order authorizing the production of coalbed methane by the operator within the boundaries of the drilling unit. The West Virginia Act also provides that, where title to subsurface minerals has been severed in such a way that title to coal and title to natural gas are vested in different persons, the operator of a coalbed methane well permitted, drilled and completed under color of title to the coalbed methane from either the coal seam owner or the natural gas owner has an affirmative defense to an action for willful trespass relating to the drilling and commercial production of coalbed methane from that well.

Alabama Regulation. In 1983, the State Oil & Gas Board of Alabama, in cooperation with the coalbed methane operator’s group, established the first rules for coalbed methane drilling, development and producing operations. The evolution of Alabama coalbed methane permits is a continuing process. The coalbed methane industry in Alabama has a long history of working closely with Alabama Department of Environmental Management and other government agencies on the continual improvement of coalbed methane permits. All of our producing assets located in Alabama were sold in June 2013.

Environmental Regulations

Our exploration and production operations are subject to significant federal, state, and local environmental laws and regulations governing environmental protection as well as the discharge of substances into the environment. These laws and regulations may restrict the types, quantities, and concentrations of various substances that can be released into the environment as a result of natural gas drilling, production, and processing activities; suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands and other protected areas or that impact protected species; require permits or other governmental authorization before commencing certain activities and require the installation of pollution control measures as a condition of such permits or authorizations; require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells; and restrict injection of liquids into subsurface strata that may contaminate groundwater. Governmental authorities have the power to enforce compliance with their laws, regulations and permits, and violations are subject to injunctive relief, as well as administrative, civil and even criminal penalties. The effects of these laws and regulations, as well as other laws or regulations that are adopted in the future could have a material adverse impact on our operations.

We believe that we are in substantial compliance with existing applicable environmental laws and regulations. However, it is possible that new environmental laws or regulations or the modification of existing laws or regulations could have a material adverse effect on our operations. As a general matter, the recent trend in environmental legislation and regulation is toward stricter standards, and this trend will likely continue. To date, we have not been required to expend extraordinary resources in order to satisfy existing applicable environmental laws and regulations. However, costs to comply with existing and any new environmental laws and regulations could become material. Moreover, a serious incident of pollution may result in the suspension or cessation of operations in the affected area or in substantial liabilities to third parties. Although we maintain insurance coverage in the amount of $5 million against costs of clean-up operations, no assurance can be given that we are fully insured against all such potential risks. The

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imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition and results of operations.

The following is a summary of some of the existing environmental laws, rules and regulations to which our operations are subject.

Comprehensive Environmental Response, Compensation and Liability Act. 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 persons who are considered to have contributed to the release of a “hazardous substance” into the environment. Many states have similar laws regarding liability for contamination, some of which may have a broader coverage than CERCLA. Under CERCLA, persons potentially liable include the owner or operator of the site where the release occurred, past owners and operators of a contaminated site who owned when the release occurred, and persons that disposed or arranged for the disposal of the hazardous substance released at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. Although CERCLA currently excludes “petroleum” and “natural gas, natural gas liquids, liquefied natural gas or synthetic gas useable for fuel” from the definition of “hazardous substance,” our operations may generate materials that are subject to regulation as hazardous substances under CERCLA. Further, not all state programs contain similar exclusions.  In addition, it is not uncommon for neighboring land owners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

CERCLA may require payment for cleanup of certain abandoned waste disposal sites, even if such waste disposal activities were undertaken in compliance with regulations applicable at the time of disposal. Under CERCLA, one party may, under certain circumstances, be required to bear more than its proportional share of cleanup costs if payment cannot be obtained from other responsible parties. CERCLA authorizes the United States Environmental Protection Agency and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. The scope of financial liability under CERCLA and similar laws involves inherent uncertainties.

Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, or RCRA, and comparable state programs regulate the management, treatment, storage, and disposal of hazardous and non-hazardous solid wastes. Our operations generate wastes, including hazardous wastes that are subject to RCRA and comparable state laws. We believe that these operations are currently complying in all material respects with applicable RCRA requirements. Although RCRA currently exempts certain natural gas and oil exploration and production wastes from the definition of hazardous waste, we cannot assure you that this exemption will be preserved in the future, which could have a significant impact on us as well as on the oil and natural gas industry, in general.

Water Discharges. Our operations are subject to the Clean Water Act, or CWA, as well as the Oil Pollution Act, or OPA, and analogous state laws and regulations. These laws and regulations impose detailed requirements, including permitting requirements, and strict controls regarding the discharge of pollutants, including spills and leaks of oil and other substances and the placement of fill material (such as from our development operations), into waters of the United States, including wetlands. Under the CWA and OPA, any unpermitted release of pollutants from operations could cause us to become subject to the costs of remediating a release; administrative, civil or criminal fines or penalties; or OPA specified damages, such as damages for loss of use, property damage and natural resource damages. Liability can be joint and several, regardless of fault. In addition, in the event that spills or releases of produced water from CBM production operations were to occur, we would be subject to spill notification and response requirements under the CWA or the equivalent state regulatory program. Depending on the nature and location of these operations, spill response plans may also have to be prepared.

Our CBM exploration and production operations produce substantial volumes of water that must be disposed of in compliance with requirements of the CWA, the Safe Drinking Water Act, or SDWA, or an equivalent state regulatory program. This produced water is disposed of by re-injection into the subsurface through disposal wells, discharge to surface streams, or in evaporation ponds. Discharge of produced water to surface streams and other bodies of water must be authorized in advance pursuant to permits issued under the CWA, and disposal of produced water in underground injection wells must be authorized in advance pursuant to permits issued under the SDWA. To date, we believe that all necessary surface discharge or disposal well permits have been obtained and that the produced water has been disposed in substantial compliance with such permits and applicable laws. More stringent regulations on our water disposal practices could have a material impact upon our operations.

Through June 14, 2013, we owned and operated an approximate 38.5-mile pipeline from the Cahaba Basin to the Black Warrior River for the disposal of produced water under a permit issued by the Alabama Department of Environmental Management (“ADEM”). All National Pollutant Discharge Elimination System (“NPDES”) permits for the discharge of produced water from coalbed methane fields in Alabama are issued for five-year terms by the ADEM and are subject to renewal every five years. We were granted an NPDES permit for the discharge of produced water from the Gurnee field into the Black Warrior River in 2004. We have

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submitted a timely and complete renewal application to ADEM for a five-year renewal of our NPDES permit. No five-year renewal NPDES permits for the discharge of produced water from coalbed methane fields into streams or rivers have been granted by ADEM since our renewal application was submitted. ADEM is currently administratively extending all existing NPDES permits for disposal of produced water from coalbed methane fields into streams or rivers for which timely and complete renewal applications are received, including our NPDES permit.

In recent federal legislative sessions, bills have been introduced to eliminate certain exemptions for hydraulic fracturing from the SDWA and to require disclosure of chemicals used in hydraulic fracturing. Several states have already adopted disclosure requirements. In addition, the EPA has recently been taking steps to assert federal regulatory authority over hydraulic fracturing using diesel under the SDWA. Further, in March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. EPA released a progress report in December 2012; final results of the study are expected in 2014. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming; this study remains subject to review. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Consequently, these studies and initiatives could spur further legislative or regulatory action regarding hydraulic fracturing or similar production operations.

Additionally, some states, regional authorities and localities have adopted or are considering adopting regulations that could restrict hydraulic fracturing.  Further, the Bureau of Land Management is considering regulations for hydraulic fracturing on land it regulates. Further, the EPA has announced an initiative under the Toxic Substances Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals.

Air Emissions. The Clean Air Act, or CAA, and comparable state laws and regulations govern emissions of various air pollutants through the issuance of permits and the imposition of other requirements. Air emissions from some equipment used in our operations, such as gas compressors, are potentially subject to regulations under the CAA or equivalent state and local regulatory programs, although many small air emission sources are expressly exempt from such regulation or are regulated through general permits or similar generic authorizations. To the extent that these air emissions are regulated, they are generally regulated by permits issued by state regulatory agencies. These permits or authorizations may place restrictions upon our air emissions and may require us to install expensive pollution control equipment. The CAA imposes administrative, civil and even criminal penalties, as well as injunctive relief, for failure to comply. To date, we believe that no unusual difficulties have been encountered in obtaining air permits, and we believe that our operations are in substantial compliance with the CAA and analogous state and local laws and regulations. However, in the future, we may be required to incur capital expenditures or increased operating costs to comply with air emission-related requirements.

On April 17, 2011, the EPA issued final rules to subject oil and gas operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells.  Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring, using a completion combustion device or by capturing the natural gas using green completions with a completion combustion device.  Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions.  The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. We are currently evaluating the effect these rules will have on our business.

Climate Change Legislation. Laws and regulations relating to climate change and greenhouse gases (“GHGs”), including methane and carbon dioxide, may be adopted and could cause us to incur material expenses in complying with them. The Environmental Protection Agency (“EPA”), as of January 2, 2011, requires the permitting of GHG emissions from stationary sources under the prevention of significant deterioration (PDS) and Title V operating permits program for all sources that have the potential to emit specific quantities of GHGs with the largest sources first subject to permitting. These permitting provisions, should they become applicable to our operations, could require controls or other measures to reduce GHG emissions from new or modified sources, and we could incur additional costs to satisfy those requirements. In November 2010, EPA published a rule establishing GHG reporting requirements for sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions, with the first annual report, for 2011, being due in March 2012. Although the rule does not limit the amount of GHGs that can be emitted, it could require us to incur significant costs to monitor, keep records of, and report GHG emissions associated with our operations.

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In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These or other potential federal and state initiatives may result in so-called cap-and-trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from its operations. These regulatory initiatives also could adversely affect the demand for and the marketability of the oil and natural gas we produce.

Other Laws and Regulations. Our operations are also subject to regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials. Furthermore, owners, lessees and operators of natural gas and oil properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land resources occasioned by drilling and production operations and the products derived there from, and are often based on negligence, trespass, nuisance, strict liability or fraud.

The Endangered Species Act was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities that would harm the species or that would adversely affect that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The United States Fish and Wildlife Service designates the species’ protected habitat as part of the effort to protect the species. A protected habitat designation or the mere presence of threatened or endangered species could result in material restrictions to our use of the land use and may materially delay or prohibit land access for our development.

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

Hydraulic Fracturing

Regulation of hydraulic fracturing is further discussed above under Water Discharge. In connection with our hydraulic fracturing operations, we diligently review best practices and industry standards, and seek to comply with all regulatory requirements in the protection of potable water sources. Protective practices include, but are not limited to, setting multiple strings of protection pipe across the potable water sources and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time, and disposing of all non-commercially produced fluids in certified disposal wells at depths below the potable water sources.

There have not been any incidents, citations or suits related to our hydraulic fracturing activities involving environmental concerns.

We did not drill and complete any wells in 2013, we do not currently plan to drill and complete any wells in 2014, and we have no proved undeveloped reserves in any of our fields at December 31, 2013.

Industry Segment and Geographic Information

We operate in one industry, which is the exploration, development and production of natural gas. Our operational activities are conducted entirely in the United States with our core operations located in the Central Appalachian Basin of Virginia and West Virginia.

Employees

At December 31, 2013, we had a total of 43 employees, all of which were full-time. None of our employees are represented by a labor union or covered by any collective bargaining agreement. We believe that our relations with our employees are generally satisfactory.

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Corporate Offices

Our corporate headquarters, which are leased by us, are located at 909 Fannin, Suite 1850, Houston, Texas 77010. Our technical and operational headquarters, which are also leased by us, are located at 5336 Stadium Trace Parkway, Suite 206, Birmingham, Alabama 35244.

Access to Company Reports

We file periodic reports, proxy statements and other information with the SEC in accordance with the requirements of the Exchange Act. We make our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to such reports available free of charge through our corporate website at www.geometinc.com as soon as reasonably practicable after we file any such report with the SEC. In addition, information related to the following items, among other information, can be found on our website: our press releases, our corporate governance guidelines, our corporate code of business ethics and conduct, our audit committee charter, and our compensation, nominating, corporate governance and ethics committee charter. You may also read and copy any document we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an internet site that contains our reports, proxy and information statements, and our other filings which are also available to the public over the internet at the SEC’s website at www.sec.gov.

Item 1A. Risk Factors

If any of the following risks develop into actual events, our business, financial condition, results of operations, cash flows, strategies and prospects could be materially adversely affected.

We are highly leveraged, our credit agreement matures on June 30, 2014, and no assurances can be made that we will be able to refinance, repay or further extend the maturity date of our credit agreement.

Although the June 2013 sale of our Alabama properties brought our borrowing base into conformity under our credit agreement, we remain highly leveraged.  In addition, our credit agreement matures on the earliest to occur of: (i) June 30, 2014, (ii) the closing of the Asset Sale pursuant to the Asset Purchase Agreement, or the sale of the Assets pursuant to a substitute purchase agreement, or (iii) the termination of the Asset Purchase Agreement or any substitute purchase agreement, and no assurances can be made that we will be able to refinance, repay or further extend the maturity date of our credit agreement.

In addition, our credit agreement no longer provides for loans to be available on a revolving basis up to the amount of the borrowing base.  As a result, the current outstanding loans, once repaid, may not be re-borrowed.  Our financial condition, and the current and future conditions in the credit markets, may impact the availability of capital resources required to meet our future financial obligations, or to provide funds for our working capital, capital expenditures and other needs for the foreseeable future.  We may not be able to obtain financing on terms satisfactory to us, or at all.

Our financial condition raises substantial doubt as to our ability to continue as a going concern.

The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States which contemplate continuation of the Company as a going concern.  If we become unable to continue as a going concern, we may have to liquidate our assets and the values we receive for our assets in liquidation or dissolution could be significantly lower than the values reflected in our financial statements. In the event the management and the board adopt a plan of liquidation, the Company would implement the liquidation basis of accounting.  Under the liquidation basis of accounting, the carrying amounts of assets as of the date of the authorization of a plan for liquidation would be adjusted to their estimated net realizable values, and liabilities, including the estimated costs associated with implementing a plan for liquidation, would be stated at their estimated settlement amounts.  Our financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Our management concluded that due to our high level of indebtedness, the uncertainties surrounding our ability to service such indebtedness and other factors, substantial doubt exists as to our ability to continue as a going concern.

Our audited financial statements for the fiscal year ended December 31, 2013 were prepared on a going concern basis in accordance with United States generally accepted accounting principles. The going concern basis of presentation assumes that we will continue in operation for the next twelve months and will be able to realize our assets and discharge our liabilities and commitments in the normal course of business and do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from our inability to continue as a going concern. Our credit agreement matures on the earliest to occur of: (i) June 30, 2014, (ii) the closing of the Asset Sale pursuant to the Asset Purchase Agreement, or the sale of the Assets pursuant to a substitute purchase agreement, or (iii) the termination of the Asset

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Purchase Agreement or any substitute purchase agreement.  Although we plan to use the cash proceeds from the Asset Sale to liquidate all of our outstanding liabilities, including repaying the outstanding balance under our credit agreement, our management team concluded that due to the uncertainties surrounding our ability to complete the Asset Sale and before the maturity date of our credit agreement, substantial doubt exists as to our ability to continue as a going concern. If we were unable to continue as a going concern, the values we receive for our assets on liquidation or dissolution could be significantly lower than the values reflected in our financial statements.

Natural gas prices have been depressed recently and have the potential to remain depressed for the next several years, which may have an adverse effect on our financial condition, results of operations and cash flows.

Natural gas prices have fallen substantially since early 2011 as a result of over-supply caused by, among other things, increased drilling in unconventional reservoirs, reduced economic activity associated with a recession and weather conditions. Natural gas prices may be depressed for the foreseeable future. All of our estimated net proved reserves and production are natural gas. Therefore, continued depressed natural gas prices may have a material adverse effect on our financial condition, results of operations and cash flows.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Natural gas prices are volatile, and sustained periods of lower natural gas prices have and will significantly affect our financial results and impede our growth.

Our revenue, profitability, and cash flow depend upon the prices for natural gas. Natural gas prices have been historically volatile, and such high levels of volatility are expected to continue. Recent prices for natural gas have been depressed and may remain depressed. Reduced natural gas prices have a significant impact on the value of our reserves, our cash flow, and our borrowing capacity. Lower natural gas prices may decrease our revenues, and may reduce the amount of natural gas that we can produce economically. This may result in substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition, results of operations, cash flow and borrowing capacity. If there are substantial downward adjustments to our estimated proved reserves, accounting rules may require us to impair, as a non-cash charge to earnings, the carrying value of our properties. No impairment charges were recorded in 2013. However, during 2012, we recorded impairment charges of $95.7 million and we may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

Primarily because of low natural gas prices in 2012, the amounts borrowed under our credit agreement exceeded the borrowing base attributable to our natural gas reserves as determined by the lenders under our credit agreement.  We have dedicated substantially all of our excess cash flow to repayment of amounts under our credit agreement.  If natural gas prices decline further or remain low for an extended period of time, we may, among other things, be unable to remain in compliance with our credit agreement.

Basis differentials could decrease and adversely affect our results of operations and cash flows.

“Basis” or “basis differential” reflects the premium or discount to quoted Henry Hub prices related to the proximity of the gas delivery point to markets and the local supply demand balance. The delivery point is generally the contractual point where ownership of the natural gas transfers from the seller and is usually a point on a pipeline or a specific delivery or market location. Prices may vary significantly from one delivery point to another. For example, natural gas prices will generally be higher if the delivery point is closer to market centers than at Henry Hub which is near producing centers. The basis differential can be affected by several factors, including weather, transportation alternatives, supply and demand and market sentiment. Historically, we have enjoyed a premium to the Henry Hub natural gas spot price for our production. However, the factors that influence these basis differentials are dynamic and beyond our control. As a result, in the future, the premiums we have enjoyed could diminish or turn to discounts.

We are highly leveraged, which has made us more vulnerable to economic downturns and has resulted in adverse developments in our business which may continue.

During most of 2012 and through June 14, 2013, the amounts outstanding under our credit agreement exceeded the borrowing base under the facility.

As of March 19, 2014, our total consolidated indebtedness under our credit agreement was $71.0 million.  This high level of indebtedness could have important consequences to our business, including the following:

·                  it will limit our flexibility in planning for or reacting to changes in our business and future business opportunities;

·                  an increase in interest rates will generate greater interest expense because the indebtedness under our revolving credit facility is at a variable interest rate;

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·                  we are more highly leveraged than some of our competitors, which may place us at a competitive disadvantage;

·                  it makes us more vulnerable to downturns in our business, our industry or the economy in general;

·                  our excess cash flows will be dedicated to the repayment of interest and principal under our credit agreement, which substantially eliminates the amount we have available to finance our exploration, development and acquisition activities or for any other purpose;

·                  there would be a material adverse effect on our business and financial condition if we were unable to service our indebtedness; and

·                  our inability to borrow any more amounts on a revolving basis under our credit agreement may impact the availability of capital resources required to meet our future financial obligations, or to provide funds for our working capital, capital expenditures and other needs for the foreseeable future.

Our obligations under our credit agreement contain covenants with which we must comply. If we are unable to comply with these covenants, our lenders could accelerate the repayment of our indebtedness and foreclose on their mortgages.

Our credit agreement imposes certain restrictions on us, including our ability to make capital expenditures, incur indebtedness and liens, make loans and investments, sell assets, engage in mergers, consolidations and acquisitions, enter into transactions with affiliates, or pay dividends.

A breach of any of the terms of our credit agreement could result in a default under such indebtedness. In the event of a default, the lenders could terminate their commitments to us, and they could accelerate the repayment of all of our indebtedness. In such case, it is unlikely that we will have sufficient funds to pay the total amount of accelerated obligations, and our lenders could proceed against the collateral securing the indebtedness. Any acceleration in the repayment of our indebtedness or related foreclosure would adversely affect our business.

Inadequate liquidity has and may continue to materially and adversely affect our business operations in the future.

Our efforts to improve our liquidity position have been challenging given the current economic climate. Current economic fundamentals portray an uncertain outlook for our natural gas business due to depressed natural gas prices and economic conditions. The depressed natural gas prices and economic conditions have resulted in a decline in our revenues and have caused us to suspend our drilling activities. Our ability to maintain adequate liquidity through 2014 may depend on consummation of a strategic transaction or sale of assets and, if so, the terms thereof, sustained commodity price improvement, reduction of operating expenses and capital spending.

Our level of indebtedness has and may continue to adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from meeting our obligations under our indebtedness.

As of December 31, 2013, our total outstanding liabilities were $90.7 million, including $71.6 million of outstanding borrowings drawn under our credit agreement which matures on the earliest to occur of: (i) June 30, 2014, (ii) the closing of the Asset Sale pursuant to the Asset Purchase Agreement, or the sale of the Assets pursuant to a substitute purchase agreement, or (iii) the termination of the Asset Purchase Agreement or any substitute purchase agreement. Our degree of leverage could have important consequences, including the following:

·                  it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, further exploration, debt service requirements, acquisitions and general corporate or other purposes;

·                  a substantial portion of our cash flows from operations will be dedicated to the payment of principal and interest on our indebtedness and will not be available for other purposes, including our operations, capital expenditures and future business opportunities;

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·                  certain of our borrowings, including borrowings under our credit agreement, are at variable rates of interest, exposing us to the risk of increased interest rates;

·                  as we have pledged substantially all of our natural gas properties and the related equipment, inventory, accounts receivable and proceeds as collateral for the borrowings under our credit agreement, they may not be pledged as collateral for other borrowings and would be at risk in the event of a default thereunder;

·                  it may limit our ability to adjust to changing market conditions and place us at a competitive disadvantage compared to our competitors that have less debt;

·                  we are vulnerable in the present downturn in general economic conditions and in our business, and we will likely be unable to carry out capital spending and exploration activities that are important to our growth; and

·                  we may, from time to time, not be in compliance with covenants under our credit agreement, which will require us to seek waivers from our banks, which may be more difficult to obtain in our current financial condition and, if obtained, may require the payment of substantial fees.

Our credit agreement matures on the earliest to occur of: (i) June 30, 2014, (ii) the closing of the Asset Sale pursuant to the Asset Purchase Agreement, or the sale of the Assets pursuant to a substitute purchase agreement, or (iii) the termination of the Asset Purchase Agreement or any substitute purchase agreement at which time all amounts outstanding thereunder will be due and payable. At current commodity prices, we do not project that we will be able to repay such borrowings without completing one or more capital raising or asset sale transactions, obtaining an extension of the credit facility from the lenders, or entering into a new credit facility.

Our substantial indebtedness has and may continue to adversely impact our business, results of operations and financial condition.

In addition to making it more difficult for us to satisfy our debt and other obligations, our substantial indebtedness has and may continue to limit our ability to respond to changes in the markets in which we operate and otherwise limit our activities. For example, our indebtedness, and the terms of agreements governing that indebtedness, has and may continue to:

·                  increase our vulnerability to economic downturns and impair our ability to withstand sustained declines in commodity prices;

·                  subject us to covenants that limit our ability to fund future working capital, capital expenditures, exploration costs and other general corporate requirements;

·                  prevent us from borrowing additional funds for operational or strategic purposes (including to fund future acquisitions), disposing of assets or paying cash dividends;

·                  limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

·                  place us at a competitive disadvantage relative to our competitors that have less debt outstanding.

Our credit agreement has substantial restrictions and covenants and our ability to comply with those restrictions and covenants is uncertain.

The terms of our credit agreement require us to comply with certain restrictions and covenants. Our ability to comply with these restrictions and covenants in the future is uncertain. Our failure to comply with any of the restrictions and covenants under our credit agreement could result in a default under those agreements, which could cause all of our existing indebtedness to be immediately due and payable.

Our credit agreement no longer allows us to borrow additional amounts on a revolving basis. We may not have the financial resources in the future to make any mandatory principal prepayments required under our credit agreement. Our inability to borrow additional funds under our credit agreement could adversely affect our operations and our financial results.

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Our capital expenditures have been limited under the terms of our credit agreement and we have been and will continue to not be able to fund the capital expenditures that would be required for us to increase reserves and production.

We must make capital expenditures to develop our existing reserves and to discover new reserves. Historically, we have financed our capital expenditures primarily with cash flow from operations, borrowings under credit facilities, sales of producing properties, and sales of debt and equity securities and we expect to continue to do so in the future. We cannot assure you that we will have sufficient capital resources in the future to finance capital expenditures.

Volatility in natural gas prices, the timing of our drilling programs and drilling results will affect our cash flow from operations. Lower prices and/or lower production will also decrease revenues and cash flow, thus reducing the amount of financial resources available to meet our capital requirements, including reducing the amount available to pursue our drilling opportunities. If our cash flow from operations does not increase as a result of planned capital expenditures, a greater percentage of our cash flow from operations will be required for debt service and operating expenses and our planned capital expenditures would, by necessity, be decreased.

Limitations under the terms of our credit agreement severely impact our ability to drill and discover new reserves. We have been limited in making capital expenditures for the last two years and consequently have not increased our reserves, production or cash flows.

Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

In recent years, the Obama administration’s budget proposals and other proposed legislation have included the elimination of certain key United States federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for United States production activities and (iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and gas within the United States. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of any legislation as a result of these proposals or any other similar changes in United States federal income tax laws could negatively affect our financial condition and results of operations.

Possible regulation related to global warming and climate change could have an adverse effect on our operations and demand for our natural gas.

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that requires reporting and reductions of the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, and the Kyoto Protocol address greenhouse gas emissions, and several countries including the European Union have established greenhouse gas regulatory systems. In the United States, at the state level, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs or have begun considering adopting greenhouse gas regulatory programs.

The EPA has issued greenhouse gas monitoring and reporting regulations that require reporting by regulated facilities in 2012 and annually thereafter. The EPA has adopted rules requiring companies to report certain greenhouse gas emissions from oil and natural gas facilities. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding serves as a first step to issuing regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. The EPA issued its “tailoring” rules requiring GHG permits for certain sources of GHG emissions.

In the courts, several decisions have been issued that may increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the oil and natural gas that we produce.

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Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities, increases in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect affect on our operations by disrupting the transportation or process-related services provided by service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. In addition, our hydraulic fracturing operations require large amounts of water. Should climate change or other drought conditions occur, our ability to obtain water in sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly.

We face uncertainties in estimating proved gas reserves, and inaccuracies in our estimates could result in lower than expected reserve quantities and a lower present value of our reserves.

Natural gas reserve engineering requires subjective estimates of underground accumulations of natural gas and assumptions concerning future natural gas prices, production levels, and operating and development costs. In addition, in the early stages of a coalbed methane project, it is difficult to predict the production curve of a coalbed methane field. The estimated production profile of a field in the early stage of operations may vary significantly from the actual production profile as the field matures. As a result, quantities of estimated proved reserves, projections of future production rates, and the timing of development expenditures may be incorrect. Over time, material changes to reserve estimates may be made, taking into account the results of actual drilling, testing, and production. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of gas we ultimately recover being different from reserve estimates.

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

·                  geological conditions;

·                  changes in governmental regulations and taxation;

·                  the amount and timing of actual production;

·                  future gas prices and operating costs; and

·                  capital costs of drilling new wells.

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

Our results of operations have and could continue to be adversely affected as a result of non-cash impairments.

Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of estimated future net revenues, discounted at 10% per annum, plus cost of properties not being amortized plus the lower of cost or fair value of unevaluated properties less income tax effects. The estimated future net revenues are estimated in accordance with SEC rules and regulations which include using a flat price throughout the life of our reserves calculated by taking the unweighted arithmetic average of the natural gas price for the first day of each month during the year. We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. During 2012, we took in impairment charges of $95.7 million. Future adverse

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changes to prices we receive for our production, costs, reserves or other factors could lead to an impairment of all or a portion of our full cost pool in future periods which could significantly reduce earnings during the period in which the impairment occurs, and would result in a corresponding reduction to the full cost pool and stockholders’ equity.

Our net operating loss carryforwards may be limited or they may expire before utilization.

As of December 31, 2013, we had United States federal tax net operating loss carryforwards (“NOL’s”) of approximately $156.0 million, which expire at various dates from fiscal year 2022 through fiscal year 2033. These net operating loss carryforwards may be used to offset future taxable income and thereby reduce our United States federal income taxes otherwise payable. Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), imposes an annual limit on the ability of a corporation that undergoes an “ownership change” to use its net operating loss carry forwards to reduce its tax liability. An “ownership change” would occur if stockholders, deemed under Section 382 to own 5% or more of our capital stock by value, increase their collective ownership of the aggregate amount of our capital stock to more than 50 percentage points over a defined period of time. In the event of certain changes in our stockholder base, we may at some point in the future experience an “ownership change” as defined in Section 382 of the Code. Accordingly, our use of the net operating loss carryforwards and credit carryforwards may be limited at some point in the future by the annual limitations described in Sections 382 and 383 of the Code.

As long as we continue not to replace our natural gas reserves, our reserves and production will continue to decline, which will continue to adversely affect our business, financial condition, results of operations, borrowing capacity and cash flows.

Producing natural gas reservoirs are typically characterized by declining production rates that vary depending upon reservoir characteristics and other factors. CBM production generally declines at a shallow rate after initial increases in production which result as a consequence of the de-pressuring process. The rate of decline from our existing wells may change in a manner different than we have estimated. Thus, our future natural gas reserves and production and, therefore, our borrowing capacity, cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find, or acquire additional reserves to replace our current and future production at acceptable costs.

Our ability to sell the gas we produce depends in substantial part on the availability and capacity of pipeline systems owned and operated by third parties. Operational impediments on these pipeline systems may hinder our access to natural gas markets or delay our production.

The availability of a ready market for our natural gas production depends on a number of factors, including the proximity of our reserves to pipelines, capacity constraints on pipelines, and disruption of transportation of natural gas through pipelines. We transport the natural gas we produce principally through pipelines owned by third parties. If we cannot access these third-party pipelines, or if transportation of gas through any of these pipelines is disrupted, we may be required to shut-in or curtail production from some of our wells or seek alternate methods of transportation of our production. If any of these were to occur, our revenues would be reduced, which would in turn have a material adverse effect on our financial condition and results of operations.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

We own leasehold interests in areas not currently held by production. Unless production in paying quantities is established on units containing these leases during their terms, these leases will expire. If our leases expire, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, including factors that are beyond our control, such as drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.

We have and may continue to be unable to obtain adequate acreage to develop additional large-scale projects.

To achieve economies of scale and produce gas economically, we need to acquire large acreage positions to reduce our per unit costs. There are a limited number of coalbed formations in North America that we believe are favorable for CBM development. We face competition when acquiring additional acreage, and we may be unable to find or acquire additional acreage at prices that are acceptable to us.

Coal mining may have an adverse effect on our business

Our gas wells are sometimes located in areas with existing surface or underground mining operations. In some cases, we may be required to temporarily or permanently abandon a producing well due to such mining operations resulting in loss of production, reserves and borrowing capacity.

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Our exploration and development activities may not be commercially successful.

The exploration for and production of natural gas involves numerous high risks. The cost of drilling, completing, and operating wells for coalbed methane or other gas is often uncertain, and a number of factors can delay or prevent drilling operations or production, including:

·                  unexpected drilling conditions;

·                  title problems;

·                  pressure or irregularities in geologic formations;

·                  equipment failures or repairs;

·                  fires or other accidents;

·                  adverse weather conditions;

·                  reductions in natural gas prices;

·                  pipeline ruptures;

·                  regulatory permitting problems;

·                  inability to dispose of produced water;

·                  legal issues; and

·                  unavailability or high cost of drilling rigs, other field services, and equipment.

Our future drilling activities may not be successful, and our drilling success rates could decline. Unsuccessful drilling activities could result in higher costs without any corresponding reserves and revenues.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions but is not subject to regulation at the federal level. The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with the final report of the study anticipated to be available in 2014, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. Although it was not passed, legislation was introduced before prior sessions of Congress to provide for increased federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states, regional authorities and localities have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, New York has imposed a de facto moratorium on the issuance of permits for high-volume, horizontal hydraulic fracturing until state-administered environmental studies are finalized. Many states have adopted programs requiring companies to disclose chemicals used in hydraulic fracturing. In addition, if hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities.

We operate in a highly competitive environment and many of our competitors have greater resources than we do.

The gas industry is intensely competitive and we compete with companies from various regions of the United States and may compete with foreign suppliers for domestic sales, many of whom are larger and have greater financial, technological, human and other resources. If we are unable to compete with them, our operating results and financial position may be adversely affected.

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In addition, larger companies may be able to pay more to acquire new properties for future exploration, limiting our ability to replace gas we produce or to grow our production. Our ability to acquire additional properties and to discover new reserves also depends on our ability to evaluate and select suitable properties and to consummate these transactions in a highly competitive environment.

Our ability to produce natural gas may be hampered by the water present in the formation, which could affect our profitability.

Coalbeds frequently contain brine water that must be removed in order for the gas to desorb from the coal and flow to the well bore. Our ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether or not we can produce gas in commercial quantities. The cost of water disposal may adversely affect our profitability.

We may face unanticipated water disposal costs.

Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies or our wells produce water in excess of our disposal capacity, we may have to shut-in wells, reduce drilling activities, or upgrade facilities. The costs to dispose of this produced water may increase if any of the following occur:

·                  we cannot obtain future permits from applicable regulatory agencies;

·                  water of lesser quality is produced;

·                  our wells produce excess water; or

·                  new laws and regulations require water to be disposed of in a different manner.

We may be unable to retain our existing senior management team and/or other key personnel that have expertise in coalbed methane extraction and our failure to continue to retain qualified new personnel could adversely affect our business.

Our business requires disciplined execution at all levels of our organization to ensure that we continually develop our reserves and produce gas at profitable levels. This execution requires an experienced and talented management and operations team. If we were to lose the benefit of the experience, efforts and abilities of any of our key executives or the members of our team that have developed substantial expertise in coalbed methane extraction, our business could be adversely affected. We do not maintain key person life insurance on any of our personnel. Our ability to manage our growth, if any, will require us to continue to train, motivate, and manage our employees and to motivate and retain additional qualified managerial and operations personnel. Competition for these types of personnel is intense, and we may not be successful in retaining the personnel required to grow and operate our business profitably.

Government laws, regulations, and other legal requirements relating to protection of the environment, health and safety matters and others that govern our business increase our costs and may restrict our operations.

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state, local, and foreign authorities, relating to protection of the environment and health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the injection of material into subsurface formations, the management and disposal of hazardous substances and wastes, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, reclamation and restoration of mining or drilling properties after mining or drilling is completed, control of surface subsidence from underground mining, and work practices related to employee health and safety. Complying with these requirements, including the terms of our permits, has had, and will continue to have, a significant effect on our respective costs of operations and competitive position. In addition, we could incur substantial costs, including clean-up costs, fines and civil or criminal sanctions, and third party damage claims for personal injury, property damage, wrongful death, or exposure to hazardous substances, as a result of violations of or liabilities under environmental and health and safety laws.

Additionally, the gas industry is subject to extensive legislation and regulation, which is under constant review for amendment or expansion. Any changes may affect, among other things, the cost of production. State and local authorities regulate various aspects of gas drilling and production activities, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of natural gas properties, environmental matters, safety standards, market sharing, and well site restoration. If we fail to comply with statutes and regulations, we may be subject to substantial penalties, which would decrease our profitability.

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We must obtain governmental and/or third party permits and approvals for drilling operations, which can be a costly and time consuming process and result in restrictions on our operations.

Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations. For example, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that proposed exploration for or production of gas may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. In some cases, consents from third parties may be required before a permit is issued. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.

We depend on technology owned by others.

We rely on the technological expertise of the independent contractors that we retain for our operations. We have no long-term agreements with these contractors, and thus we cannot be sure that we will continue to have access to this expertise.

We may incur additional costs to produce gas because our confirmation of title for gas rights for some of our properties may be inadequate or incomplete.

We generally obtain title opinions on significant properties that we drill or acquire. However, we cannot be sure that we will not suffer a monetary loss from title defects or failure. In addition, the steps needed to perfect our ownership varies from state to state and some states permit us to produce the gas without perfected ownership under forced pooling arrangements while other states do not permit this. As a result, we may have to incur title costs and pay royalties to produce gas on acreage that we own and these costs may be material and vary depending upon the state in which we operate.

We do not insure against all potential risks. We may incur substantial losses and be subject to substantial liability claims as a result of our natural gas operations.

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations.

Pinnate well plugging has and may continue to result in higher than expected costs.

Pinnate wells are multi-lateral horizontal wells with two well bores and there is limited history or experience related to plugging procedures or techniques. As a result, it is possible that the plugging cost may vary from lease to lease based on lateral length, hole stability, coal mining activity and regulatory changes.

Cyber attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.

To our knowledge, we have not experienced cyber attacks in the past; however, there is no assurance that we will not suffer such attacks and attendant losses in the future. Further, as cyber attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber attacks. If our systems for protecting against cyber security risks prove not to be sufficient, we could be adversely affected such as by having our business systems compromised, our proprietary information altered, lost or stolen, or our operations disrupted.

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Risks Related to the Asset Sale

The announcement and pendency of the Asset Sale, whether or not consummated, may adversely affect our business.

The announcement and pendency of the Asset Sale, whether or not consummated, may adversely affect the trading price of our Common Stock and Preferred Stock, our business or our relationships with customers, suppliers and employees. As a result of our announcement of the Asset Sale, third parties may be unwilling to enter into material agreements with respect to our business. New or existing customers may prefer to enter into agreements with our competitors who have not expressed an intention to sell their business because customers may perceive that such relationships are likely to be more stable. If we fail to complete the proposed Asset Sale, the failure to maintain existing business relationships or enter into new ones is likely to materially and adversely affect our business, results of operations and financial condition.

In addition, pending the completion of the Asset Sale, we may be unable to attract and retain key personnel and our management’s focus and attention and employee resources may be diverted from operational matters during the pendency of the Asset Sale.

In the event that the Asset Sale is not completed, the announcement of the termination of the Asset Purchase Agreement may also adversely affect the trading price of our Common Stock and Preferred Stock, our business or our relationships with lenders, customers, suppliers and employees.

We cannot be sure if or when the Asset Sale will be completed.

The consummation of the Asset Sale is subject to the satisfaction or waiver of various conditions, including the authorization of the Asset Sale by our stockholders. We cannot guarantee that the closing conditions set forth in the Asset Purchase Agreement will be satisfied. If we are unable to satisfy the closing conditions in the Buyer’s favor or if other mutual closing conditions are not satisfied, the Buyer will not be obligated to complete the Asset Sale.

If the Asset Sale is not completed, our board of directors, in discharging its fiduciary obligations to our stockholders, will evaluate other strategic alternatives that may be available. Such other strategic alternatives may not be as favorable to our stockholders as the Asset Sale. These may include remaining an operating company, potentially under the supervision of the United States Federal Bankruptcy Courts, which may reduce cash and assets available to our stockholders in the event of a later dissolution. Any future sale of substantially all of our assets or other transactions may be subject to further stockholder approval.

Our executive officers and directors may have interests in the Asset Sale other than, or in addition to, the interests of our stockholders generally.

Members of our board of directors and our executive officers may have interests in the Asset Sale that are different from, or are in addition to, the interests of our stockholders generally. Our board of directors was aware of these interests and considered them, among other matters, in approving the Asset Purchase Agreement.

We will continue to incur the expenses of complying with public company reporting requirements following the closing of the Asset Sale.

After the Asset Sale, we will continue to be required to comply with the applicable reporting requirements of the Exchange Act, even though compliance with such reporting requirements is economically burdensome.

While the Asset Sale is pending, it creates uncertainty about our future that could have a material adverse effect on our business, financial condition and results of operations.

While the Asset Sale is pending, it creates uncertainty about our future. As a result of this uncertainty, our current or potential business partners may decide to delay, defer or cancel entering into new business arrangements with us pending completion or termination of the Asset Sale. In addition, while the Asset Sale is pending, we are subject to a number of risks, including:

·                  the diversion of management and employee attention from our day-to-day business;

·                  the potential disruption to business partners and other service providers; and

·                  the possible inability to respond effectively to competitive pressures, industry developments and future opportunities.

The occurrence of any of these events individually or in combination could have a material adverse effect on our business, financial condition and results of operation.

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If the Asset Sale is not completed and the Asset Purchase Agreement is terminated, there may not be any other offers from potential acquirers.

If the Asset Sale is not completed and the Asset Purchase Agreement is terminated, we may seek another purchaser for the Assets. There can be no assurances that we would be able to enter into meaningful discussions or to otherwise complete any transaction with any other party who may have an interest in purchasing the Assets on terms acceptable to us. Additionally, the inability to complete the Asset Sale could make potential acquirers more reluctant to engage in a transaction with us.

There is no guarantee that the holders of our Preferred Stock will receive any of the net cash proceeds from the proposed Asset Sale in the form of dividends, and we could spend or invest the net cash proceeds from the Asset Sale in ways in which our stockholders may not agree.

The purchase price for the sale of the Assets will be paid directly to the Company. The Company plans to use the cash proceeds from the Asset Sale to satisfy all of its outstanding liabilities, including repaying the outstanding balance under its credit agreement. The Company expects the proceeds from the Asset Sale to exceed the Company’s liabilities and any such excess amount will be used to make severance, retention and change of control payments to certain employees and members of the Company’s senior management and for normal working capital and operating expense purposes. We currently anticipate that the Asset Sale would be followed by either a merger or a dissolution and distribution of our remaining assets in accordance with applicable law.

The terms of our outstanding Preferred Stock provide that the holders of the Preferred Stock would be entitled to a liquidation preference before the holders of our Common Stock would be entitled to receive any of the consideration in a merger or a distribution of remaining assets in the event of a dissolution. Currently, the liquidation preference to which the holders of our Preferred Stock are entitled totals approximately $60 million in the aggregate, which is more than the excess net proceeds anticipated to be received from the Asset Sale.  Therefore, absent a concession from the holders of our Preferred Stock, the holders of our Common Stock will not receive any consideration as a result of the Asset Sale and the subsequent merger or dissolution.

Absent concessions from the holders of our Preferred Stock, the holders of our Common Stock will not receive any of the proceeds from the Asset Sale.

The purchase price for the Assets will be paid directly to us.  We estimate that, if we complete the transactions contemplated in the Asset Purchase Agreement at the end of the second quarter of 2014, our remaining cash following the Asset Sale will be approximately $23 million, which is based on the purchase price of $107 million as adjusted by various estimated costs, including the cash flows for production months from the effective date to the anticipated closing date at the end of the second quarter, outstanding bank debt and other liabilities, transaction costs, federal income taxes, hedge termination costs, severance, retention and change of control payments to certain employees and members of the Company’s senior management and other working capital requirements. The estimates and assumptions used have not taken into account any potential reduction in the purchase price due to preferential right exercises, title or environmental defects or other potential adjustments to the purchase price under the Asset Purchase Agreement. Therefore, because the holders of our Preferred Stock are entitled to an approximately $60 million liquidation preference, absent a concession from the holders of our Preferred Stock, no proceeds of the Asset Sale will be received by the holders of our Common Stock.

We may be exposed to litigation related to the Asset Sale from the holders of our Common Stock.

Transactions such as the Asset Sale are often subject to lawsuits by stockholders. Because the holders of our Common Stock will not receive any consideration from the Asset Sale, it is possible that they may sue the Company or its board of directors.

If the Asset Sale is not consummated, we will likely file bankruptcy.

If the Asset Sale is not consummated and we are unable to find another viable purchaser for our assets, we will likely file bankruptcy as we will have no operating assets to continue the business.

If the Asset Sale is not consummated, our lenders will likely foreclose on all of our assets.

As an accommodation to allow time to complete the Asset Sale, our lenders recently agreed to extend the maturity date of our credit agreement from April 1, 2014 to the earliest to occur of: (i) June 30, 2014, (ii) the closing of the Asset Sale pursuant to the Asset Purchase Agreement, or the sale of the Assets pursuant to a substitute purchase agreement, or (iii) the termination of the Asset Purchase Agreement or any substitute purchase agreement. This extension required the unanimous consent of each of the six lenders in the credit facility.  In the event the Asset Sale is not completed by June 30, 2014, and no further extensions of time are agreed to by the lenders, we would be in default under our credit agreement.  Upon the occurrence of an event of default, the lenders could accelerate the repayment of all of our indebtedness. In such case, it is unlikely that we will have sufficient funds to pay the total

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amount of accelerated obligations, and our lenders could proceed against the collateral securing the credit facility. Any acceleration in the repayment of our indebtedness or related foreclosure would adversely affect our business and likely require us to seek protection under federal bankruptcy statutes.

We will incur significant expenses in connection with the Asset Sale and could be required to make significant payments if the Asset Purchase Agreement is terminated under certain conditions.

If we are unable to close the Asset Sale due to an uncured breach of our representations, warranties, covenants or obligations under the Asset Purchase Agreement, we may owe contractual damages to the Buyer that would likely exhaust our cash reserves.  In the event we breach our representations or warranties prior to the closing of the Asset Sale, the Buyer may reduce the purchase price by an amount up to $7,000,000. In addition, we expect to pay legal fees, accounting fees and proxy filing costs whether or not the Asset Sale closes. Any significant expenses or payment obligations incurred by us in connection with the Asset Sale could adversely affect our financial condition and cash position.

The Asset Purchase Agreement requires us to pay certain costs if we accept an alternative to the Asset Sale.

The Asset Purchase Agreement contains provisions that make it more difficult for us to sell our assets to a party other than the Buyer. In the event the Asset Purchase Agreement is terminated for select reasons by the Buyer or GeoMet, GeoMet is obligated to pay a termination fee to the Buyer in the amount of $4,280,000.

The Asset Purchase Agreement may expose us to contingent liabilities.

Under the Asset Purchase Agreement, we are required to indemnify the Buyer for certain various claims, subject to a time limitation and fixed maximum on GeoMet’s total indemnity exposure. Significant indemnification claims by the Buyer could have a material adverse effect on our financial condition.

Risks Related to Our Capital Stock

On an as-converted basis, our Preferred Stock currently represents approximately 53% of the outstanding shares and therefore would have the ability to control any vote requiring the approval of our shareholders and may take actions that conflict with the interests of the other stockholders.

The interests of the holders of Preferred Stock could conflict with your interests as a holder of Common Stock. For example, the holders of Preferred Stock may have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in their judgment, could enhance their equity investment, even though such transactions might involve risks to you, as minority holders of the Company, including a vote to approve a sale transaction and any subsequent merger or liquidation.

The terms of our Preferred Stock prohibit us from issuing Common Stock at a price of less than the conversion price at the time of issuance without approval of a at least 50% of the holders of the Preferred Stock, which has and may continue to limit our ability to access the capital markets. We have granted certain rights to a holder of our Preferred Stock which has and may continue to limit certain of the transactions we may enter into.

The terms of our Preferred Stock provide that we may not issue any additional shares of Common Stock (or securities convertible into Common Stock) for consideration per share (with regard to securities convertible into Common Stock, on an as-converted basis) less than the then-current conversion price of the Preferred Stock without the prior vote or consent of holders of a at least 50% of the outstanding shares of Preferred Stock, for so long as at least 750,000 shares of Preferred Stock remain outstanding. The current price of our Common Stock is significantly lower than the conversion price of our Preferred Stock.  This provision has and will continue to prevent us from issuing Common Stock or securities convertible into our Common Stock for the foreseeable future, without the consent of the holders of our Preferred Stock, which has and may continue to adversely affect our liquidity and results of operations.

In 2010, we entered into an agreement with Sherwood Energy LLC (“Sherwood”) in connection with a rights offering of Preferred Stock to our stockholders in which Sherwood agreed to acquire any shares of Preferred Stock not acquired by our shareholders pursuant to the rights offering. Pursuant to this agreement, Sherwood is entitled to appoint up to two persons to our board of directors. In addition, without the consent of the Sherwood directors, we are prohibited from entering into certain corporate transactions. We also granted Sherwood the right to acquire additional securities that we may issue in the future, subject to the terms of the agreement. In addition, if we default under this agreement, Sherwood will have the right to appoint a majority of our directors, until the default is waived. If the default is not cured or waived within a year, Sherwood will have the right to require us to redeem the Preferred Stock it owns. See “Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities — Preferred Stock.”

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The terms of our Preferred Stock has and may continue to prohibit us from obtaining long term financing or additional equity.

The terms of our Preferred Stock currently provide that we pay in-kind dividends (“PIK”) at 12.5% or in cash at a rate of 8% until September 14, 2015, at which time the cash dividend rate will increase to 9.6%. At such date, we will no longer have the option to pay these dividends in-kind.  The Company does not anticipate paying any cash dividends during the period it has the option to pay PIK dividends. The Preferred Stock is redeemable at the election of the preferred holders beginning 8 years after the effective date of the Preferred Stock issuance.  The cumulative impact of paying PIK dividends negatively impacts our ability to obtain equity because of the significant dilutive effects on our Common Stock.   In addition, the 9.6% cash dividend may impede our ability to raise debt financing.

Our Common Stock has experienced, and may continue to experience, price volatility and a low trading volume.

The trading price of our Common Stock has been and may continue to be subject to large fluctuations, which may result in losses to investors. Our stock price may increase or decrease in response to a number of events and factors, including:

·                  results of our drilling or the results of drilling by offset operators;

·                  global economic recession;

·                  trends in our industry and the markets in which we operate;

·                  changes in the market price of the natural gas we sell;

·                  changes in financial estimates and recommendations by securities analysts;

·                  acquisitions and financings;

·                  quarterly variations in operating results;

·                  operating and stock price performance of other companies that investors may deem comparable to us; and

·                  issuances, purchases or sales of blocks of our Common Stock.

This volatility may adversely affect the price of our Common Stock regardless of our operating performance.

Two existing stockholders each beneficially own a significant percentage of our Common Stock, which has and may continue to limit your ability to influence the outcome of stockholder votes.

Sherwood beneficially owns approximately 31% of our Common Stock outstanding as of December 31, 2013 (after giving effect to the conversion of the Preferred Stock held by Sherwood) and Yorktown Energy Partners IV, L.P. (“Yorktown”) beneficially owns approximately 14% of our Common Stock. Additional shares of our Preferred Stock may be issued to Sherwood and our other holders of our Preferred Stock as paid-in-kind dividends (“PIK dividends”). In addition, two of the current members of our board of directors are appointed by Sherwood and another member of our board of directors is a member and a manager of the general partner of Yorktown. As a result, Sherwood and Yorktown have, and can be expected to have, a significant voice in our affairs, in the outcome of stockholder voting concerning the election of directors, the adoption or amendment of provisions in our charter and bylaws, the approval of mergers and other significant corporate transactions.

You may experience dilution of your ownership interests due to the future issuance of additional shares of our Common Stock.

We may in the future issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present holders of our Common Stock. We are currently authorized to issue 125,000,000 shares of Common Stock and 10,000,000 shares of Preferred Stock with such designations, preferences and rights as determined by our board of directors. As of December 31, 2013, 40,652,317 shares of Common Stock were outstanding, and 46,158,238 shares of Common Stock are issuable upon conversion of outstanding Preferred Stock. An additional 1,401,261 shares of our Preferred Stock, convertible into 10,778,930 shares of Common Stock, are reserved for issuance and some or all of that amount may be issued to our holders of our Preferred Stock as PIK dividends. The potential issuance of such additional shares of Common Stock may create downward pressure on the trading price of our Common Stock. We may also issue additional shares of our Common Stock or other securities that are convertible into or exercisable for Common Stock in connection with the hiring of personnel, future acquisitions, future private placements of our securities for capital raising purposes, or for other business purposes. Any such issuance would further dilute the interests of our existing holders of our Common Stock.

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Future sales of our Common Stock by our existing stockholders may depress our stock price.

As of December 31, 2013, 40,652,317 shares of our Common Stock were outstanding, together with outstanding options representing the right to purchase up to 1,574,198 shares. As of December 31, 2013, our outstanding Preferred Stock is convertible into an aggregate of 46,158,238 shares of our Common Stock, which represents approximately 53% of our issued and outstanding Common Stock as of December 31, 2013, as converted. Sales of a substantial number of shares of our Common Stock in the public market, or the perception that these sales may occur, could cause the market price of our Common Stock to decline.

We have not previously paid dividends on our Common Stock and we do not anticipate doing so in the foreseeable future.

We have not in the recent past paid, and do not anticipate paying in the foreseeable future, cash dividends on our Common Stock. Our credit agreement contains covenants that prohibit our ability to pay dividends on our Common Stock. Additionally, any future decision to pay a dividend and the amount of any dividend paid, if permitted, will be made at the discretion of our board of directors.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

From time to time we are a party to litigation in the normal course of business. While the outcome of lawsuits or other proceedings against us are not possible to reasonably predict, management does not believe that the adverse effect on our financial condition, results of operations or cash flows, if any, will be material.

Environmental and Regulatory

As of December 31, 2013, there were no known environmental or other regulatory matters related to our operations that are reasonably expected to result in a material liability to us.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Common Stock

On May 10, 2012, we received approval from NASDAQ to transfer the listing of our Common Stock and Preferred Stock from The NASDAQ Global Market to The NASDAQ Capital Market. Our Common Stock and Preferred Stock began trading on The NASDAQ Capital Market at the opening of the market on May 14, 2012. On August 3, 2012, we received a notice from NASDAQ advising us that our Common Stock had failed to regain compliance with the $1.00 minimum bid price requirement for continued listing on The NASDAQ Capital Market and, as a result, our Common Stock was delisted from The NASDAQ Capital Market at the opening of business on August 13, 2012.  Our Common Stock now trades on the OTCQB under the symbol “GMET”. The table below shows the high and low closing prices of our Common Stock for the periods indicated.

Approximately 2,500 stockholders of record as of March 1, 2014 held our Common Stock. In many instances, a registered stockholder is a broker or other entity holding shares in street name for one or more customers who beneficially own the shares. holders of our Common Stock are entitled to receive dividends if, as and when such dividends are declared by our board of directors

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out of assets legally available therefore after payment of dividends required to be paid on shares of Preferred Stock, if any. We have not declared or paid any dividends on our shares of Common Stock and do not currently anticipate paying any dividends on our shares of Common Stock in the future. Currently our plan is to retain any future earnings for use in the operations and to reduce our outstanding borrowings. Our credit agreement prohibits us from paying any cash dividends.

Preferred Stock

On September 14, 2010, we issued and sold 4,000,000 shares of our Preferred Stock at a price of $10.00 per share, pursuant to a rights offering. The Preferred Stock is our most senior equity security. The Preferred Stock ranks senior to our Common Stock and junior to all of our existing indebtedness. Our Preferred Stock is listed on the NASDAQ Global Market under the symbol “GMETP”. The table below shows the high and low closing prices of our Preferred Stock for the periods indicated.

Approximately 300 stockholders of record as of March 1, 2014 held our Preferred Stock. In many instances, a registered stockholder is a broker or other entity holding shares in street name for one or more customers who beneficially own the shares. The applicable annual rate for dividends paid in cash is 8.0% for the first three years and 9.6% thereafter. We have not paid any dividends in cash through December 31, 2013, except for those cash dividends paid for partial shares of PIK dividends. The applicable annual rate for PIK dividends, which can be paid until the fifth anniversary of the closing of the Preferred Stock offering, is 12.5%. All dividends are cumulative and all unpaid dividends compound on a quarterly basis at a 12.5% annual rate. Our credit agreement contains a restrictive covenant which influences our ability to pay cash dividends. Cash dividends in excess of $2 million are permitted only if our ratio of debt-to-trailing twelve-month EBITDA, as defined in the credit agreement and after giving effect to such cash dividend payment, is 3.5 to 1.0 or less.

The terms of our outstanding Preferred Stock provide that in the event of a liquidation or dissolution of the Company, the holders of our Preferred Stock would be entitled to a liquidation preference before the holders of our Common Stock would be entitled to receive any distributions from the Company.  The liquidation preference is equal to the original investment amount of the Preferred Stock ($40 million) plus paid-in-kind shares plus accrued and unpaid dividends, and currently totals approximately $60 million.  Therefore, if the Company is dissolved following the Asset Sale, the estimated remaining net proceeds (approximately $23 million) would be less than the liquidation preference to which the holders of our Preferred Stock are currently entitled ($60 million).  Absent a concession from the holders of our Preferred Stock, the holders of our Common Stock would not receive any distributions as a result of the Asset Sale or subsequent dissolution of the Company.

It is not clear that the terms of our outstanding Preferred Stock would entitle the holders of our Preferred Stock to a liquidation preference in the event the Company was to engage in a merger.   If our outstanding Preferred Stock is not entitled to a liquidation preference in the event of a merger, then the Preferred Stock might instead exercise its rights to convert into Common Stock, and then participate with the Common Stock in the proceeds of such transaction on an as-converted basis.  Assuming the remaining net proceeds from the Asset Sale are approximately $23 million, this would mean that the holders of our Preferred Stock would receive less in a merger than the holders of our Preferred Stock would receive in a dissolution as a result of their liquidation preference.  In order for the Company to engage in a merger, the Company would have to receive the approval of the holders of at least fifty percent (50%) of the outstanding shares of Preferred Stock voting separately as a class, in addition to the approval of a majority of the outstanding shares of Common Stock including the outstanding shares of Preferred Stock voting on an as-converted basis treated as a single class.  The Company has been advised by the holders of more than fifty percent (50%) of our Preferred Stock that they will not vote in favor of a merger unless the terms of the transaction provide that the holders of our Preferred Stock will be entitled to receive at least the same value or distributions as such holders would have been entitled to receive in a dissolution pursuant to the liquidation preference to which the holders of the Preferred Stock are entitled.  As a result, absent a concession from the holders of our Preferred Stock, it is likely that the holders of our Common Stock would not receive any distributions if the Asset Sale is followed by a merger.

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In 2010, we entered into an agreement with Sherwood in connection with a rights offering of Preferred Stock made to our stockholders, pursuant to which Sherwood agreed to acquire any shares of Preferred Stock not acquired by our stockholders pursuant to the rights offering. Sherwood currently owns 58.6% of our Preferred Stock and owns 31.1% of our Common Stock on an as-converted basis. Sherwood is entitled to appoint two members to our board of directors so long as it beneficially owns more than 40% of our Preferred Stock, or beneficially owns 20% or more of our Common Stock, on an as-converted basis. Sherwood may appoint one member to our board of directors so long as it beneficially owns 40% of the Preferred Stock it acquired, or beneficially owns 10 % or more of our Common Stock, on an as-converted basis. Sherwood is entitled to appoint one of its designated directors to our Audit and Compensation Committees, provided that the director meets applicable independence requirements.

In addition, such agreement provides that, for so long as Sherwood beneficially owns more than 40% of our Preferred Stock, or beneficially owns 10% or more of our Common Stock, on an as-converted basis, we may not incur additional material debt, issue additional equity securities senior to or pari passu with the Preferred Stock, engage in any material acquisitions or other significant corporate transactions, or engage in certain other activities without the consent of the director(s) designated by Sherwood.

If we default under such agreement, Sherwood has the right to appoint a majority of the members of our board of directors until such default is cured or waived by Sherwood. If the default continues for more than 12 months (absent a cure or waiver), Sherwood has the right to require us to redeem its shares of Preferred Stock at the redemption price.

Such agreement also grants Sherwood a participation right to purchase its pro rata share, up to $30,000,000, of authorized but unissued debt securities and Preferred Stock, and all rights, options or warrants to purchase shares and securities of any type convertible into or exchangeable for debt securities or Preferred Stock.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

We did not purchase any of our equity securities during the fourth quarter of 2013.

Equity Compensation Plan Information

The following table summarizes information regarding the number of shares of our Common Stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2013.

Item 6. Selected Financial Data

Not applicable.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the financial statements and the related notes and other information included elsewhere in this report.

Overview

GeoMet is primarily engaged in the exploration for and development and production of natural gas from coal seams (“coalbed methane” or “CBM”). All of our production is CBM, which is a dry natural gas containing no hydrocarbon liquids.  GeoMet was incorporated under the laws of the state of Delaware on November 9, 2000. We were originally founded as a consulting company to

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the coalbed methane industry in 1985 and have been active as an operator, developer and producer of coalbed methane properties since 1993.  Our operations are concentrated in the central Appalachian Basin in Virginia and West Virginia.

The natural gas industry is capital intensive.  Natural gas markets traditionally have been highly volatile.  We have historically made substantial capital expenditures in the exploration, development and acquisition of natural gas reserves.  Our capital expenditures have been financed primarily with internally generated cash flows from operations, bank borrowing and equity raises.

Developments in 2013

Natural gas prices in 2012 were depressed compared with prices generally prevailing during prior years and historically low natural gas prices have continued in 2013.  The low natural gas prices in 2012 and 2013 had pervasive adverse consequences to our business, including a borrowing base deficiency under our credit agreement. On August 8, 2012, we amended our credit agreement to include a conforming tranche equal to the borrowing base, and a non-conforming tranche in the amount of outstanding loans in excess of the borrowing base. The amendment required that we use nearly all of our excess cash flows to reduce outstanding borrowings under our credit agreement and significantly limited our capital expenditures.

In February 2013, GeoMet engaged Lantana Oil & Gas Partners (“Lantana”) to assist GeoMet in connection with the sale of GeoMet’s assets in the Black Warrior Basin of Alabama. On June 14, 2013, we closed the sale of the Alabama properties and used approximately $57.0 million of the proceeds to repay outstanding borrowings under our credit agreement. After this repayment, borrowings outstanding under our credit agreement totaled $77 million. In connection with this repayment the non-conforming portion of borrowings was repaid and the Company no longer has a borrowing base deficiency under our credit agreement. As of December 31, 2013, the interest rates applied to borrowings was 3.24%.  At that time, our credit agreement had a maturity date of April 1, 2014.

In September 2013, GeoMet’s board of directors requested that FBR Capital Markets & Co. (“FBRC”) solicit indications of interest from third parties regarding a potential acquisition of GeoMet. GeoMet’s board of directors did not find any of the proposals it received as a result of that process sufficiently attractive to pursue at that time.  In November 2013, we concluded that process, and engaged Lantana to assist us in pursuing the sale of all or substantially all of our assets.  In November 2013, GeoMet and FBRC amended the terms of FBRC’s engagement to terminate FBRC’s services as its financial advisor in connection with a potential transaction except and to the extent GeoMet requested that FBRC render an opinion with respect to the fairness of the consideration to be received in connection with a proposed transaction. In addition to any fees payable to FBRC in connection with such opinion, FBRC remained entitled to certain fees in the event GeoMet consummated a transaction with certain third parties.

Recent Developments

On February 13, 2014, the Company and its wholly-owned subsidiaries, GeoMet Operating Company, Inc. and GeoMet Gathering Company, LLC (collectively as a group, the “Sellers”), entered into an asset purchase agreement (the “Asset Purchase Agreement”) to sell substantially all of the Company’s remaining assets, comprising coalbed methane interests and other assets (collectively, the “Assets”) located in the Appalachian Basin in McDowell, Harrison, Wyoming, Raleigh, Barbour and Taylor Counties, West Virginia and Buchanan County, Virginia (the “Asset Sale”) to ARP Mountaineer Productions, LLC, a Delaware limited liability company (the “Buyer”) and a wholly-owned subsidiary of Atlas Resource Partners, L.P., a Delaware limited partnership (“Atlas”), for a purchase price of $107 million, subject to various purchase price adjustments.  Atlas has provided an irrevocable guaranty of ARP Mountaineer’s performance of its obligations under the Asset Purchase Agreement.  The effective date of the Asset Sale is January 1, 2014, and it is expected to close in the second quarter of 2014 subject to the satisfaction of certain closing conditions, which includes obtaining the approval of the holders of (i) at least fifty percent (50%) of the outstanding shares of GeoMet’s Series A Convertible Redeemable Preferred Stock, par value $0.001 (the “Preferred Stock”), entitled to vote at a special meeting of the stockholders of GeoMet and (ii) a majority of the outstanding shares of GeoMet’s common stock, par value $0.001 (the “Common Stock”) including the outstanding shares of Preferred Stock on an as-converted basis voting together with the holders of Common Stock as a single class.

On February 13, 2014, at the meeting of the GeoMet board of directors to consider and approve the Asset Purchase Agreement, FBRC rendered its opinion to the GeoMet board of directors as to, as of February 13, 2014, the fairness, from a financial point of view, to GeoMet of the consideration of $107 million to be received by GeoMet for the Assets, subject to the assumed liabilities, in the Asset Sale pursuant to the Asset Purchase Agreement.

The Asset Purchase Agreement contains customary representations and warranties of the parties and covenants of the Sellers. The Asset Purchase Agreement also provides for the parties to indemnify each other with respect to certain matters, subject to certain limitations on time and amount.

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The Asset Purchase Agreement includes certain termination rights, including, among others, the right of (i) the Buyer to terminate if GeoMet’s board of directors makes a change in recommendation regarding the Asset Sale, (ii) the Company to terminate if GeoMet’s board of directors elects to pursue a superior proposal, or (iii) either the Buyer or GeoMet to terminate if GeoMet’s stockholders do not approve the Asset Sale. Under certain circumstances, the termination of the Asset Purchase Agreement will result in the payment of a termination fee to the Buyer.

The final net proceeds will be reduced after accounting for the cash flows from the effective date to the closing date. The Company plans to use the cash proceeds to liquidate all of its outstanding liabilities, including repaying the outstanding balance under its credit agreement.  The Company expects the proceeds from the Asset Sale to exceed the Company’s liabilities and any such excess amount shall be used to make severance, retention and change of control payments to certain employees and members of the Company’s senior management and for normal working capital and operating expense purposes as the Company continues to evaluate strategic alternatives.

Approval of the Asset Sale will be submitted to our stockholders for their consideration, and, on March 27, 2014, the Company filed with the SEC a definitive proxy statement on Schedule 14A to be used to solicit stockholder approval of the transaction.

On February 28, 2014, we amended our credit agreement to extend the maturity date from April 1, 2014 to the earliest to occur of: (i) June 30, 2014, (ii) the closing of the Asset Sale pursuant to the Asset Purchase Agreement, or the sale of the Assets pursuant to a substitute purchase agreement, or (iii) the termination of the Asset Purchase Agreement or any substitute purchase agreement, in order to allow a reasonable time to properly close the Asset Sale.  In connection with this amendment, we paid the bank group a fee of $133,125.

Our board of directors intends to continue to evaluate other strategic alternatives if the Asset Sale is approved by our stockholders.  We currently anticipate that the Asset Sale would be followed by either a merger or a dissolution and distribution of our remaining assets in accordance with applicable law.

During 2011 and the first five months of 2012, prices received for natural gas in the United States continued to decline significantly which we believe, among other things, was due to an over-supply of natural gas, primarily resulting from shale drilling and reduced demand due to a much warmer winter than normal. On April 21, 2012, the Henry Hub spot price closed at $1.825/ MMBtu, its lowest in over ten years. Presented below are the NYMEX Settle Prices for the period January 2011 through March 2014 and the NYMEX Forward Curve Prices (as of March 18, 2014) for natural gas for the period April 2014 through December 2014.

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Areas of Operation

Our core areas of operations are in the Central Appalachian Basin of Virginia and West Virginia. The Central Appalachian Basin is a mountainous region where coal mining is prevalent. We previously had operations located in the Black Warrior and Cahaba Basins in Alabama. On June 14, 2013, the Company closed the sale of all of its coalbed methane properties located in Alabama.

Central Appalachia

Pond Creek and Lasher Fields—We are the operator of 298 producing vertical CBM wells in which we own a 99.0% average working interest in the Pond Creek and Lasher fields located in southern West Virginia and southwestern Virginia. At December 31, 2013, approximately 91% of our estimated proved developed reserves, or 92.5 Bcf, is in the Pond Creek field. Net daily sales of gas averaged 15.4 MMcf per day for 2013. Our natural gas production from the Pond Creek field is delivered into the Jewell Ridge pipeline system owned by East Tennessee Natural Gas, LLC (“ETNG”). We have two long-term transportation agreements with ETNG which went into effect in April 2007 with total maximum daily quantities of 15,000 MMBtu’s and 10,000 MMBtu’s and primary terms of 15 years and 10 years, respectively. Our gas from the Lasher field is delivered into the Columbia Gas Transmission pipeline with firm transportation for 500 MMBtu’s per day. We also own and operate a 12 mile, 8 inch high-pressure steel pipeline and gas treatment and compression facilities through which the Pond Creek field natural gas production is gathered, dehydrated, and compressed for delivery into the Jewell Ridge Lateral of the East Tennessee pipeline system. In addition, we own and operate a disposal well to dispose of produced water from both the Pond Creek and Lasher fields.

Pinnate Horizontal Wells—We are the operator of 44 producing pinnate horizontal CBM wells in which we own a 71.6% average working interest in central and northern West Virginia. We also have a 33.7 % average working interest in 67 non-operated pinnate horizontal wells in central West Virginia. At December 31, 2013, approximately 6% of our estimated proved developed reserves, or 6.1 Bcf, is associated with these pinnate horizontal wells. Net daily sales of natural gas averaged 7.6 MMcf per day for 2013.  We are party to two firm transportation agreements with total maximum daily capacity of 18,500 MMBtu per day and primary terms expiring from April 2013 through November 2024 which can be automatically extended at GeoMet’s option at the maximum tariff rate. We are also party to a 10,000 MMBtu per day gathering contract that is currently in a month-to-month evergreen term.  In some cases, our natural gas sales volumes are delivered to market under transportation agreements controlled by our working interest partners. Generally, our natural gas sales volumes are sold at a delivery point into the respective interstate pipeline system utilized.

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Alabama

On June 14, 2013, the Company closed the sale of all of its coalbed methane properties located in Alabama. Net daily sales of natural gas from our Alabama properties averaged 9.7 MMcf per day through June 14, 2013.

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements that have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make assumptions and estimates that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. We base our estimates on historical experience and various other assumptions that we believe are reasonable; however, actual results may differ. Our significant accounting policies are described in Note 4 to our audited consolidated financial statements included elsewhere in this annual report. We believe the following critical accounting policies involve significant judgments, estimates, and a high degree of uncertainty in the preparation of our financial statements.

Reserves. Our most significant financial estimates are based on estimates of proved gas reserves. Proved gas reserves represent estimated quantities of gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production, and timing of development expenditures, including many factors beyond our control. The estimation process relies on assumptions and interpretations of available geologic, geophysical, engineering, and production data and, the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geologic interpretation, and judgment. In addition, as a result of changing market conditions, natural gas prices and future development costs will change from year to year, causing estimates of proved reserves to also change. Estimates of proved reserves are key components of our most significant financial estimates involving our unevaluated properties, our rate for recording depreciation, depletion and amortization and our full cost ceiling limitation. Our reserves are fully engineered on an annual basis by Prator Bett, L.L.C., independent petroleum engineers.

Natural Gas Properties—The method of accounting for natural gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. We use the full cost method of accounting for natural gas properties as prescribed by the SEC. Under this method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our natural gas properties are capitalized.

Natural gas properties are depleted using the units-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estimated proved gas reserves. Estimation of proved gas reserves relies on professional judgment and use of factors that cannot be precisely determined. Subsequent proved reserve estimates materially different from those reported would change the depletion expense recognized during the future reporting period. No gains or losses are recognized upon the sale or disposition of natural gas properties unless the sale or disposition represents a significant quantity of gas reserves, which would have a significant impact on the depreciation, depletion and amortization rate.

Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair value of unevaluated properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date. The ceiling limitation test is calculated using natural gas prices in effect as of the balance sheet date and adjusted for regional price differentials, held constant over the life of the reserves. In addition, subsequent to the adoption of Accounting Standards Codification (“ASC”) 410-20-25, the future cash outflows associated with settling asset retirement obligations are not included in the computation of the discounted present value of future net revenues for the purposes of the ceiling limitation test calculation.

Asset Retirement Obligations —We adopted ASC 410-20-25, effective January 1, 2003. It establishes accounting and reporting standards for retirement obligations associated with tangible long-lived assets that result from the legal obligation to plug, abandon and dismantle existing wells and facilities that we have acquired, constructed or developed. It requires that the fair value of the liability for asset retirement obligations be recognized in the period in which it is incurred. Upon initial recognition of the asset retirement obligation, the asset retirement cost is capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the

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useful life of the related asset. Periodically, we update the cost assumptions resulting from changes in market and environmental regulation and revise the liability recorded accordingly.

Income Taxes—We record our income taxes using an asset and liability approach in accordance with the provisions of ASC 740. This results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax bases of assets and liabilities using enacted tax rates at the end of the period. Under ASC 740, the effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. This assessment includes extensive analysis performed by the Company at the end of each reporting period. At December 31, 2013, a full valuation allowance has been recorded against our net deferred tax asset.

Estimating the amount of valuation allowance is dependent on estimates of future taxable income, alternative minimum tax income, and changes in stockholder ownership that could trigger limits on use of net operating losses under Internal Revenue Code Section 382. We have a significant deferred tax asset associated with net operating loss carryforwards (“NOL’s”).

ASC 740 also clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements and prescribes a consistent threshold and measurement attribute for financial statement recognition and disclosure of tax positions taken, or expected to be taken, on a tax return. The adoption of this pronouncement did not have a significant impact on the Company’s consolidated financial statements.

Revenue Recognition and Gas Balancing—We derive revenue primarily from the sale of produced natural gas. We use the sales method of accounting for the recognition of gas revenue whereby revenues, net of royalties, are recognized as the production is sold to a purchaser. The amount of gas sold may differ from the amount to which the Company is entitled based on its working interest or net revenue interest in the properties. In instances where we have wellhead imbalances, we use the entitlements method. A ready market for natural gas allows us to sell our natural gas shortly after production at various pipeline receipt points at which time title and risk of loss transfers to the buyer. Revenue is recorded when title is transferred based on our nominations and net revenue interests. Pipeline imbalances occur when our production delivered into the pipeline varies from the gas we nominated for sale or depending on the agreement in place, imbalances may be made up in future production or are settled with cash approximately thirty days from date of production and are recorded as either a reduction or increase of revenue depending upon whether we are over-delivered or under-delivered.

Settlements of gas sales occur after the month in which the gas was produced. We estimate and accrue for the value of these sales using information available at the time financial statements are generated. Differences are reflected in the accounting period during which payments are received from the purchaser.

Derivative Instruments and Hedging Activities—Our hedging activities consist of derivative instruments entered into in order to hedge against changes in natural gas prices primarily through the use of fixed price swap agreements, basis swap agreements, three-way collars, and traditional collars. Consistent with our hedging policy, we have entered into a series of derivative instruments to hedge a significant portion of our expected natural gas production through 2014. Typically, these derivative instruments require payments to (receipts from) counterparties based on specific indices as required by the derivative agreements. These transactions are recorded in our audited consolidated financial statements in accordance with ASC 815. Although not risk free, we believe this policy will reduce our exposure to natural gas price fluctuations and thereby achieve a more predictable cash flow. As a result, our derivative instruments are cash flow hedge transactions in which we are hedging the variability of cash flow related to a forecasted transaction. We do not enter into derivative instruments for trading or other speculative purposes. At December 31, 2013, we do not have the ability to enter into additional natural gas hedges because we do not have the credit capacity with our existing natural gas hedge counterparties.

In accordance with ASC 815-20-25, as amended, all our derivative instruments are recorded on the balance sheet at fair value and changes in the fair value of the derivatives are recorded each period in current earnings for the natural gas derivatives. The natural gas derivatives have not been designated as hedge transactions.

At the inception of a derivative contract, we may designate the derivative as a cash flow hedge. For all derivatives designated as cash flow hedges, we document the relationship between the derivative instrument and the hedged items as well as the risk management objective for entering into the derivative instrument. To be designated as a cash flow hedge transaction, the relationship between the derivative and hedged items must be highly effective in achieving the offset of changes in cash flows attributable to the risk both at the inception of the derivative and on an ongoing basis.

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Mezzanine Equity—Our Preferred Stock has been classified within the mezzanine (temporary) equity section of the Consolidated Balance Sheets because the shares are redeemable at the option of the holder and therefore do not qualify for permanent equity.

Fair Value Measurement—Effective January 1, 2008, we adopted ASC 820-10-55, which provides a framework for measuring fair value under GAAP. ASC 820-10-55 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. ASC 820-10-55 also establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The standard describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities. Level 3 inputs are derived from unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. See disclosure provided in the Notes to Consolidated Financial Statements.

Stock-Based Compensation—We follow the fair value recognition provisions of ASC 718. The application of ASC 718 requires the use of an option pricing model, such as the Black Scholes model, to measure the estimated fair value of the options and as a result various assumptions must be made by management that require judgment and the assumptions could be highly uncertain. For share-based awards outstanding prior to the adoption of ASC 718, we will continue using the accounting principles originally applied to those awards before adoption. Therefore, we do not recognize any equity compensation cost on these prior awards in the future unless such awards are modified, repurchased or cancelled.

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Natural Gas Production Operations Summary

The table below presents information on gas revenues, sales volumes, production expenses and per Mcf data for the years ended December 31, 2013 and 2012. This table should be read with the discussion of the results of operations for the periods presented below (in thousands, except per Mcf amounts).

(1)                  Average natural gas sales price realized includes the effects of realized gains and losses on derivative contracts.

(2)                  On June 14, 2013, the Company closed the sale of all of its coalbed methane properties located in the state of Alabama.

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Results of Operations

Year Ended December 31, 2013 compared with Year Ended December 31, 2012

The following are selected items derived from our Consolidated Statement of Operations and their percentage changes from the comparable period are presented below.

NM-Not Meaningful

Gas sales. Gas sales decreased by $1.1 million, or 3%, to $38.1 million compared to the prior year period. Gas sales decreased $5.5 million resulting from the sale of our Alabama properties on June 14, 2013 (the “Asset Sale”) and $3.4 million resulting from production declines in the remaining properties, offset by an increase of $7.8 million resulting from higher natural gas prices in the current year period.

Lease operating expenses. Lease operating expenses decreased by $4.4 million, or 25%, to $13.1 million compared to the prior year period. Lease operating expenses decreased $3.3 million due to the Asset Sale, $0.8 million resulting from the reversal of over-accrued ad valorem taxes paid in August 2013, and $0.3 million due to natural production declines in the remaining properties.

Compression expense. Compression expense decreased by $0.4 million, or 8%, to $4.3 million compared to the prior year period due to the Asset Sale.

Transportation expense. Transportation expense decreased by $0.3 million, or 8%, to $3.4 million compared to the prior year period. Transportation expense decreased $0.2 million due to the Asset Sale and $0.1 million due to contract expirations or renegotiations.

Production taxes. Production taxes increased by $0.1 million, or 7%, to $2.1 million compared to the prior year period. Production taxes increased by $0.4 million due to the increase over time as our West Virginia exemptions diminish, offset by a decrease of $0.3 million due to the Asset Sale.

Depreciation, depletion and amortization. Depreciation, depletion and amortization decreased by $6.9 million, or 60%, to $4.6 million compared to the prior year period. This decrease was primarily due to the $95.7 million in impairments recorded to our natural gas properties in 2012 and the sale of our Alabama properties on June 14, 2013.

Impairment of natural gas properties. During the prior year period, the gross carrying value of the Company’s natural gas properties exceeded the full cost ceiling limitations measured quarterly and, as such, a $95.7 million aggregate impairment of natural gas properties was recorded. No such impairments were recorded in the current year period.

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Impairment of intangible asset. During the prior year period, the remaining value of $0.8 million related to a drilling license was written off due to no future drilling plans in place resulting from the depressed natural gas price environment. No such impairments were recorded in the current year period.

General and administrative. General and administrative expense increased by $0.2 million, or 3%, to $5.0 million compared to the prior year period. Included in general and administrative expense was a decrease in professional fees, offset by non-recurring executive compensation. In November 2012, the Compensation Committee approved the payment of a contingent bonus in the amount of $0.4 million to be paid to the named executive officers in connection with the elimination of the borrowing base deficiency that existed under our credit agreement.

Realized gains on derivative contracts. Realized gains on derivative contracts were $1.1 million in the current year period which included a $1.2 million realized loss related to natural gas swap positions terminated in order to prevent the Company from being over-hedged after the closing of the sale of its coalbed methane properties in Alabama. Realized losses represent net cash flow settlements paid to the contract counterparty, while realized gains represent net cash flow settlements paid to us from the contract counterparty. Realized losses occur when natural gas prices exceed the derivative ceiling prices. Conversely, realized gains occur when natural gas prices go below the derivative floor prices.

Unrealized losses from the change in market value of open derivative contracts. Unrealized losses on open derivative contracts were $2.9 million in the current year period. Unrealized gains and losses are non-cash transactions that occur when the corresponding asset or liability derivative contracts are marked-to-market at the end of each reporting period.

Gain on the sale of Properties in Alabama. On June 14, 2013, the Company closed the sale of all of its coalbed methane properties located in the state of Alabama, recording a gain on the sale of $36.9 million, as described in Note 2— Sale of Coalbed Methane Properties in Alabama in the Notes to Consolidated Financial Statements.

Interest expense. Interest expense decreased by $0.7 million, or 12%, to $5.1 million compared to the prior year period. This decrease was primarily due to the $57.0 million repayment of outstanding borrowings under our credit agreement resulting from the sale of our Alabama properties on June 14, 2013.

Income tax expense. The income tax expense in the current year period was different than the amount computed using the statutory rate primarily due to a $13.2 million reduction of the valuation allowance on our deferred tax asset. A reconciliation of the effective tax rate to the statutory rate for the year ended December 31, 2013 is rate is as follows:

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Liquidity and Capital Resources

Cash Flows and Liquidity

Natural gas prices in 2012 were depressed compared with prices generally prevailing during prior years.  Such natural gas prices resulted in significant property impairments, a full valuation of our net deferred tax asset, and a borrowing base deficiency under our credit agreement during 2012.  Although natural gas prices were slightly improved in 2013, they continued to be depressed when compared to periods preceding 2012.

As of December 31, 2013, we had a working capital deficit of $69.2 million, a retained deficit of $266.7 million and stockholders’ deficit of $79.3 million.  Depressed natural gas prices in 2012 resulted in significant property impairments and full valuation of our deferred tax assets during 2012. On April 2, 2013, due to a maturity date of April 1, 2014, all the indebtedness under our credit agreement was reclassified to current liabilities.  In addition, our Preferred Stock continues to accrue a dividend of 12.5% per annum, which we have been paying through the issuance of additional shares of Preferred Stock.  Beginning in September 2015, dividends on the Preferred Stock will accrue at 9.6% per annum and be payable in cash.

Cash flows provided by operations for the year ended December 31, 2013 were $8.8 million, down $9.6 million from the prior year period. The decrease was primarily due to a $7.3 million decrease in natural gas sales primarily resulting from production volumes lost in the sale of our Alabama properties and $1.2 million in realized hedging losses related to natural gas swap positions terminated in order to prevent the Company from being over-hedged after the closing of the sale of its coalbed methane properties in Alabama. Cash flows provided by operations of $8.8 million for the year ended December 31, 2013 and the net proceeds from the sale of our Properties in Alabama of $60.7 million were sufficient to fund net cash used in financing activities of $67.8 million, consisting almost entirely of repayments of borrowings under our credit agreement.

The June 2013 sale of our Alabama assets brought our borrowing base into conformity under our credit agreement; however, we remain highly leveraged. On February 13, 2014, we entered into an agreement to sell our Central Appalachian assets (the “Asset Sale”), which represent substantially all of our remaining assets for $107 million, subject to various purchase price adjustments.  The Asset Sale is described below in “Pending Sale of Central Appalachian Assets” section below. We expect to close this transaction in the second quarter of 2014; however, the closing is subject to numerous closing conditions such as an approval of the transaction by our stockholders.  No assurance can be given that the Asset Sale will be consummated. In order to allow a reasonable time to close the Asset Sale and repay all outstanding liabilities and obligations, on February 28, 2014, we amended our credit agreement to extend the maturity date from April 1, 2014 to the earliest to occur of: (i) June 30, 2014, (ii) the closing of the Asset Sale pursuant to the Asset Purchase Agreement, or the sale of the Assets pursuant to a substitute purchase agreement, or (iii) the termination of the Asset Purchase Agreement or any substitute purchase agreement. No assurances can be made that we will be able to refinance, repay or further extend the maturity date of our credit agreement. For additional information related to our credit agreement, see “Credit Agreement” section below.

Pending Sale of Central Appalachian Assets

Pursuant to the Asset Purchase Agreement, we will sell the Assets for $107 million in cash, subject to certain purchase price adjustments specified in the Asset Purchase Agreement to account for cash flows from the effective date of the Asset Purchase Agreement to closing. The Company plans to use the purchase price proceeds received at the closing of the Asset Sale to satisfy all of its outstanding liabilities, including repaying the outstanding balance under its credit agreement. The Company expects that the proceeds from the Asset Sale will exceed the Company’s liabilities.

Assuming the Asset Sale closes at the end of the second quarter of 2014, the Company currently estimates that the purchase price will be adjusted downward approximately $7 million to account for cash flows from the effective date to closing, that the outstanding balance of its credit agreement will be approximately $66 million, and that the Company’s other liabilities (including federal income taxes and hedge termination costs (which could vary substantially given volatility in prevailing natural gas prices)) will total approximately $4 million.  The excess net proceeds will also be used to pay the Company’s transaction costs and expenses (currently estimated to total approximately $3 million), and to make severance, retention and change of control payments to certain employees and members of the Company’s senior management (currently estimated to total approximately $4 million).

Assuming, for these purposes only, that the foregoing estimates are accurate, we currently estimate that the remaining balance of the net proceeds would total approximately $23 million.

The remaining balance of the net proceeds will be used for normal working capital and operating expense purposes while the Company evaluates its next steps. We currently anticipate that the Asset Sale would be followed by either a merger or a dissolution and distribution of our remaining assets in accordance with applicable law.

As of December 31, 2013, our Central Appalachian assets remain classified as long-lived asset in our Audited Consolidated Balance Sheet. Due to circumstances surrounding the pending sale of our Central Appalachian assets, it has become likely that we will classify these assets as Assets Held For Sale in our unaudited consolidated balance sheet as of March 31, 2014 and report the operating results as discontinued operations in our unaudited consolidated statement of operations for the three months then ended.

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The terms of our outstanding Preferred Stock provide that in the event of a liquidation or dissolution of the Company, the holders of our Preferred Stock would be entitled to a liquidation preference before the holders of our Common Stock would be entitled to receive any distributions from the Company.  The liquidation preference is equal to the original investment amount of the Preferred Stock ($40 million) plus paid-in-kind shares plus accrued and unpaid dividends, and currently totals approximately $60 million.  Therefore, if the Company is dissolved following the Asset Sale, the estimated remaining net proceeds (approximately $23 million) would be less than the liquidation preference to which the holders of our Preferred Stock are currently entitled ($60 million).  Absent a concession from the holders of our Preferred Stock, the holders of our Common Stock would not receive any distributions as a result of the Asset Sale or subsequent dissolution of the Company.

It is not clear that the terms of our outstanding Preferred Stock would entitle the holders of our Preferred Stock to a liquidation preference in the event the Company was to engage in a merger.   If our outstanding Preferred Stock is not entitled to a liquidation preference in the event of a merger, then the Preferred Stock might instead exercise its rights to convert into Common Stock, and then participate with the Common Stock in the proceeds of such transaction on an as-converted basis.  Assuming the remaining net proceeds from the Asset Sale are approximately $23 million, this would mean that the holders of our Preferred Stock would receive less in a merger than the holders of our Preferred Stock would receive in a dissolution as a result of their liquidation preference.  In order for the Company to engage in a merger, the Company would have to receive the approval of the holders of at least fifty percent (50%) of the outstanding shares of Preferred Stock voting separately as a class, in addition to the approval of the holders of a majority of the outstanding shares of Common Stock including the outstanding shares of Preferred Stock voting on an as-converted basis treated as a single class.  The Company has been advised by the holders of more than fifty percent (50%) of our Preferred Stock that they will not vote in favor of a merger unless the terms of the transaction provide that the holders of our Preferred Stock will be entitled to receive at least the same value or distributions as such holders would have been entitled to receive in a dissolution pursuant to the liquidation preference to which the holders of the Preferred Stock are entitled.  As a result, absent a concession from the holders of our Preferred Stock, it is likely that the holders of our Common Stock would not receive any distributions if the Asset Sale is followed by a merger.

Credit Agreement

During 2012, the amounts borrowed under our credit agreement exceeded the borrowing base.  Borrowings under our credit agreement at August 8, 2012 totaled $148.6 million. On August 8, 2012, in connection with the excess of borrowings over the borrowing base, we amended our credit agreement to provide for a tranche A loan in the amount of our borrowing base and a tranche B loan in the amount of the excess.

On June 14, 2013, we closed the sale of all of our coalbed methane properties located in the state of Alabama. Simultaneously with the close of the property sale, approximately $57.0 million was used to repay outstanding borrowings under our credit agreement, which eliminated the borrowing base deficiency. After this repayment, borrowings outstanding under our credit agreement totaled $77.0 million.

Our credit agreement no longer provides for loans to be available on a revolving basis up to the amount of the borrowing base. As a result, the current outstanding loans, once repaid, may not be re-borrowed. All outstanding borrowings under our credit agreement are due and payable on the earliest to occur of: (i) June 30, 2014, (ii) the closing of the Asset Sale pursuant to the Asset Purchase Agreement, or the sale of the Assets pursuant to a substitute purchase agreement, or (iii) the termination of the Asset Purchase Agreement or any substitute purchase agreement. Our borrowing base is defined to be the equal to the amount borrowed under our credit agreement. Our credit agreement provides for interest to accrue at a rate calculated, at our option, at the Adjusted Base Rate plus a margin of 2.00% or the London Interbank Offered Rate (the “LIBOR Rate”) plus a margin of 3.00%. Adjusted Base Rate is defined to be the greater of (i) the agent’s base rate or (ii) the federal funds rate plus one half of one percent or (iii) the LIBOR Rate plus a margin of 1.00%. All financial covenants were deleted by the Amendment and were replaced with a capital expenditure covenant (a maximum of $1.5 million in 2012 and $1.0 million in 2013 and thereafter). As of December 31, 2013, we had $71.6 million of borrowings outstanding under our credit agreement. As of December 31, 2013, the interest rates applied to borrowings were 3.24%

Capital Expenditures

The following table is a summary of our capital expenditures on an accrual basis by category for the years ended December 31, 2013 and 2012 (in thousands):

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In 2012, we revised our estimates primarily related to the costs to plug and abandonment our horizontal Pinnate wells, resulting in a $4.8 million non-cash charge to our full cost pool, offset by an increase to our asset retirement obligation. We are limited under our credit agreement to incur capital expenditures other than those necessary to maintain current operations and leases of no more than $0.6 million in 2014.

Natural Gas Price Risk and Related Hedging Activities

The energy markets have historically been volatile, and there can be no assurance that future natural gas prices will not be subject to wide fluctuations. In an effort to reduce the effects of the volatility of the price of natural gas on our operations, management has adopted a policy of hedging natural gas prices primarily using derivative instruments in the form of three-way collars, traditional collars and swaps. While the use of these hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements. Our price risk management policy strictly prohibits the use of derivatives for speculative positions.

We have historically entered into hedging transactions, generally for forward periods up to two years or more, which increase the probability of achieving our targeted level of cash flows. Our credit agreement limits amounts of future natural gas production that we may hedge. At December 31, 2013, we do not have the ability to enter into additional natural gas hedges because we do not have the credit capacity with our existing natural gas hedge counterparties.

Swaps exchange floating price risk in the future for a fixed price at the time of the hedge. Costless collars set both a maximum ceiling (a sold ceiling) and a minimum floor (a bought floor) future price. We have accounted for these transactions using the mark-to-market accounting method. Generally, we incur accounting losses on derivatives during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctuations in our Consolidated Balance Sheets and Consolidated Statements of Operations.

Commodity Price Risk and Related Hedging Activities

At December 31, 2013, we had the following natural gas collar positions:

At December 31, 2013, we had the following natural gas swap position:

We have hedged approximately 48% of our forecasted production for 2014.

Operating Lease Commitments

We have operating leases for office space, office equipment and field compressors expiring in various years through 2019. Future minimum lease commitments as of December 31, 2013 under non-cancelable operating leases having remaining terms in excess of one year are as follows:

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Total rental expenses under operating leases were approximately $2.3 million and $2.8 million for the years ended December 31, 2013 and 2012, respectively.

Transportation and Gathering Contracts—As of December 31, 2013, under the following firm transportation contracts, we can transport maximum daily volumes of (1) 500 MMBtu’s continuing until October 31, 2015, (2) 15,000 MMBtu’s continuing until April 1, 2022, (3) 10,000 MMBtu’s continuing until April 1, 2017, (4) 15,000 MMBtu’s continuing until October 31, 2024, (5) and 10,000 MMBtu’s continuing until June 30, 2017. We have a right to extend each of these contracts at the maximum tariff rate. Additionally, we have a firm gathering contract for daily volumes of 10,000 Dth’s through June 30, 2017. As of December 31, 2013, the maximum commitment remaining under the transportation and gathering contracts is approximately $23.9 million.

Other Commitments

In the event that the Asset Sale described in Note 3— Going Concern and Management’s Plans is terminated for select reasons by GeoMet, GeoMet is obligated to pay a termination fee to the buyer in the amount of $4,280,000, as well as any professional fees associated with the termination.

Impact of Inflation

Inflation has not had a significant impact on our operations during the two years in the period ended December 31, 2013.  We believe that inflation will not have a significant near-term impact on our financial position.

Recent Accounting Pronouncements

In July 2013, the FASB issued ASU No. 2013-10, “Derivatives and Hedging (Topic 815): Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes”. The amendments in ASU 2013-10 permit the Fed Funds Effective Swap Rate (OIS) to be used as a United States benchmark interest rate for hedge accounting purposes under Topic 815, in addition to UST and LIBOR. The amendments also remove the restriction on using different benchmark rates for similar hedges. The amendments are effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. The Company has adopted and applied the provisions of ASU 2013-10 which did not impact its operating results, financial position or cash flows.

In March 2013, the FASB issued ASU 2013-07, “Presentation of Financial Statements (Topic 205): Liquidation Basis of Accounting.” The amendments require an entity to prepare its financial statements using the liquidation basis of accounting when liquidation is imminent. Liquidation is imminent when the likelihood is remote that the entity will return from liquidation and either (a) a plan for liquidation is approved by the person or persons with the authority to make such a plan effective and the likelihood is remote that the execution of the plan will be blocked by other parties or (b) a plan for liquidation is being imposed by other forces (for example, involuntary bankruptcy). If a plan for liquidation was specified in the entity’s governing documents from the entity’s inception (for example, limited-life entities), the entity should apply the liquidation basis of accounting only if the approved plan for liquidation differs from the plan for liquidation that was specified at the entity’s inception. The amendments require financial statements prepared using the liquidation basis of accounting to present relevant information about an entity’s expected resources in liquidation by measuring and presenting assets at the amount of the expected cash proceeds from liquidation. The entity should include in its presentation of assets any items it had not previously recognized under United States GAAP but that it expects to either sell in liquidation or use in settling liabilities (for example, trademarks). The amendments are effective for entities that determine liquidation is imminent during annual reporting periods beginning after December 15, 2013, and interim reporting periods therein. Entities should apply the requirements prospectively from the day that liquidation becomes imminent. Early adoption is permitted.

In February 2013, the FASB issued ASU No. 2013-04, “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date”. ASU 2013-04 provides guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations addressed within existing guidance. The update is effective for interim and annual periods beginning after December 15, 2013 and is required to be applied retrospectively to all prior periods presented for those obligations that existed upon adoption of ASU 2013-04. We are presently assessing the potential impact of ASU 2013-04.

In February 2013, the FASB issued ASU No. 2013-02, “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”, to improve the transparency of reporting reclassifications out of accumulated other comprehensive income. The update requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required under accounting principles generally accepted in the United States (“GAAP”) to be reclassified in its entirety to net income. For other amounts that are not required under GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under GAAP that provide additional detail about those amounts. The amendments are effective prospectively for reporting periods beginning after December 15, 2012. The Company has adopted and applied the provisions of ASU 2013-02 which did not impact its operating results, financial position or cash flows.

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In January 2013, the FASB issued ASU No. 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” The amendments in this update clarify that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with ASC 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. The amendments are effective during interim and annual periods beginning on or after January 1, 2013. The Company has adopted and applied the provisions of ASU 2013-01. See disclosure provided in Note 10—Derivative Instruments and Hedging Activities.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk. Our major commodity price risk exposure is to the prices received for our natural gas production. Realized commodity prices received for our production are the spot prices applicable to natural gas. Prices received for natural gas are volatile and unpredictable and are beyond our control. For the year ended December 31, 2013, a 10% decrease in the prices received for natural gas production would have decreased our gas revenues by approximately $3.8 million, which would have been offset by approximately $2.9 million by increased realized gas hedging gains.

Interest Rate Risk. We have long-term debt subject to the risk of loss associated with movements in interest rates. As of December 31, 2013, we had $71.6 million of borrowings outstanding under our credit agreement. As of December 31, 2013, the interest rate applied to borrowings was 3.24%. For the year ended December 31, 2013, interest on the borrowings averaged 4.10% per annum. All of the debt outstanding under our credit agreement accrues interest at floating or market rates. Fluctuations in market interest rates will cause our interest costs to fluctuate. Based upon the weighted average balance outstanding under our credit agreement, a 1% increase in market interest rates would have increased interest expense and negatively impacted our cash flows for the year ended December 31, 2013 by approximately $0.3 million.

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Item 8. Financial Statements and Supplementary Data

GEOMET, INC. AND SUBSIDIARIES

Index to Financial Statements

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders
GeoMet, Inc.

We have audited the accompanying consolidated balance sheets of GeoMet, Inc. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity (deficit) and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GeoMet, Inc. and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the consolidated financial statements, the Company has suffered recurring losses from operations and has a net working capital deficiency that raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 3. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Hein & Associates LLP

Houston, Texas
March 31, 2014

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GEOMET, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS