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.
Natural gas prices are volatile, and sustained periods of lower natural gas prices would significantly affect our financial results and impede our growth.
Our revenue, profitability, and cash flow depend upon the prices and demand for natural gas. Natural gas prices in general, and our regional prices in particular, have been historically highly volatile, and such high levels of volatility are expected to continue in the future. Even relatively modest drops in prices can affect our financial results and impede our growth. Changes in natural gas prices have a significant impact on the value of our reserves, our cash flow, and our borrowing capacity. Prices for natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:
•
the domestic and foreign supply of natural gas;
•
overall domestic and global economic conditions;
•
the consumption pattern of industrial consumers, electricity generators, and residential users;
•
weather conditions;
•
technological advances affecting energy consumption;
•
technological advances affecting natural gas supply such as recent development of shale gas;
•
governmental regulations;
•
proximity and capacity of gas pipelines and other transportation facilities; and
•
the price and availability of alternative fuels.
Many of these factors are beyond our control. Because all of our estimated proved reserves as of December 31, 2010 were natural gas reserves, our financial results are sensitive to movements in natural gas prices. Recent natural gas prices have been extremely volatile and we expect this volatility to continue. For example, during 2009 natural gas prices declined to less than $3.00 per Mcf, the lowest level since 2002, before recovering later that year. During 2010, the Henry Hub spot price for natural gas ranged from $3.18 per Mcf to $7.51 per Mcf.
The results of increased investment in the exploration for and production of natural gas and other factors, such as global economic and financial conditions discussed below, may cause the price of gas to fall. Lower natural gas prices may not only decrease our revenues on a per Mcf basis, but also 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 and cash flow. If there are substantial downward adjustments to our estimated proved reserves or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to impair, as a non-cash charge to earnings, the carrying value of our properties. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carry amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.
If natural gas prices decline further or remain low for an extended period of time, we may, among other things, be unable to maintain our borrowing capacity or extend the maturity of our revolving credit facility, repay current or future indebtedness or obtain additional capital on satisfactory terms, all of which could adversely affect the value of our common stock and preferred stock.
Basis differentials could decrease and adversely effect 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 have indebtedness, which makes us more vulnerable to economic downturns and adverse developments in our business.
We have incurred bank debt amounting to approximately $80.5 million as of December 31, 2010. As a result of our indebtedness, we must use a portion of our cash flow to pay interest, which reduces the amount we have available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate. Our indebtedness under our revolving credit facility is at a variable interest rate. As such, an increase in interest rates will generate greater interest expense. The amount of our debt makes us more vulnerable to economic downturns and adverse developments in our business.
Our revolving credit facility contains a number of financial and other covenants, and our obligations under the revolving credit facility are secured by substantially all of our assets. If we are unable to comply with these covenants, our lenders could accelerate the repayment of our indebtedness.
Our revolving credit facility subjects us to a number of covenants that impose restrictions on us, including our ability to incur indebtedness and liens, make loans and investments, sell assets, engage in mergers, consolidations and acquisitions, enter into transactions with affiliates, or pay dividends. We are also required by the terms of our revolving credit facility to comply with certain financial ratios. Our revolving credit facility also provides for periodic redeterminations of our borrowing base, which may affect our borrowing capacity. Our revolving credit facility is secured by a lien on substantially all of our assets, including equity interests in our subsidiaries.
A breach of any of the covenants imposed on us by the terms of our revolving credit facility, including the financial covenants, 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, we may not have sufficient funds to pay the total amount of accelerated obligations, and our lenders could proceed against the collateral securing the revolving credit facility. Any acceleration in the repayment of our indebtedness or related foreclosure would adversely affect our business.
In addition, the borrowing base under our revolving credit facility is redetermined semi-annually and may be redetermined at other times upon request by the lenders under certain circumstances. Redeterminations are based upon a number of factors, including natural gas prices and quantities of proved reserves.
Our revolving credit facility currently expires in September 2013.
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.
Among the changes contained in President Obama’s fiscal year 2012 budget proposal, released by the White House on February 14, 2011, is the elimination or deferral of certain key U.S. federal income tax deductions currently available to oil and gas exploration and production companies. Such proposed changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Recently, members of the U.S. Congress have considered similar changes to the existing federal income tax laws that affect oil and gas exploration and production companies, which, if enacted, would negatively affect our financial condition and results of operations. The passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and gas exploration and development, and any such change 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 counties 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 went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter. In November 2010, the EPA issued a final rule 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. EPA has proposed such greenhouse gas regulations and may issue final rules this year.
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.
Recent federal legislation could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.
We enter into a number of commodity derivative contracts in order to hedge a portion of our natural gas production and, periodically, interest expense. On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act. Title VII of the Dodd-Frank Act (titled “Wall Street Transparency and Accountability”) repeals prior regulatory exemptions for over-the-counter (OTC) derivatives and, for the first time, creates a comprehensive framework for the regulation of the derivatives market and, in connection therewith, expands the power of the SEC and, in particular, the Commodity Futures Trading Commission (or CFTC). Among the provisions of the Dodd-Frank Act that may affect derivatives transactions are certain clearing and trade-execution requirements; establishing capital and margin requirements for certain derivatives participants; establishing business conduct standards, recordkeeping and reporting requirements; and providing the CFTC with authority to impose position limits in the OTC derivatives markets. The Dodd-Frank Act may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties.
Many of the key concepts and processes under the Dodd-Frank Act are not defined and must be delineated by rules and regulations to be adopted by applicable regulatory agencies. As a consequence, it is not possible at this time to predict the effects that the Dodd-Frank Act or these new rules and regulations may have on our hedging activities. To the extent that we are subject to capital or margin requirements relating to, or restrictions on, our hedging activities or the costs associated with hedging activities increase, it could have an adverse effect on our ability to hedge the risks associated with our business, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If a consequence of the legislation and regulations is to lower commodity prices, our revenues could be adversely affected. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.
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 United States Securities and Exchange Commission, 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 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 could 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. We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. Future adverse changes to any of these 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, 2010, we had U.S. federal tax net operating loss carryforwards of approximately $113.2 million, which expire at various dates from fiscal year 2022 through fiscal year 2030. The years that contributed most to our federal net operating loss carryforwards were fiscal years 2003, 2004, 2005 and 2009 in the amount of $20.5, $17.2, $22.4 and $20.4 million respectively and that portion of the losses will expire in fiscal years 2023, 2024, 2025 and 2029 respectively. These net operating loss carryforwards may be used to offset future taxable income and thereby reduce our U.S. 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.
Unless we replace our natural gas reserves, our reserves and production will decline, which would 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.
Currently the vast majority of our producing properties are located in two counties in Alabama, one county in West Virginia, and one county in Virginia, making us vulnerable to risks associated with having our production concentrated in a few areas.
The vast majority of our producing properties are geographically concentrated in two counties in Alabama, one county in West Virginia, and one county in Virginia. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters, interruption of transportation of natural gas produced from the wells in these basins, or other events which impact these areas.
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.
As of December 31, 2010, we own leasehold interests in approximately 50,000 net acres in areas we believe are prospective for the Chattanooga Shale. A large portion of the acreage is 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, including 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 may 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.
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 results of the study anticipated to be available by late 2012, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states 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, a draft of which must be published by June 1, 2011, followed by a 30-day comment period. 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 U.S. and Canada 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, our operating results and financial position may be adversely affected.
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 and shales 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 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.
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 Alabama Department of Environmental Management (“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 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.
Obtaining production from our additional drilling locations could take five years or longer, making them susceptible to uncertainties that could alter the occurrence of their drilling.
The additional drilling locations on our existing acreage represent a significant part of our growth strategy. Our ability to drill and produce these locations depends on a number of uncertainties, including, but not limited to, natural gas prices, permitting and the availability of capital. Additionally, the size of these projects dictates that development proceeds in an orderly manner to assure continuity of resources and producibility. Furthermore, the additional drilling locations on acreage in our two early-stage CBM development projects and our Chattanooga Shale exploration prospect face additional uncertainties regarding the economic returns achievable in these areas where only a few wells have been drilled to date.
Our operations in British Columbia present unique risks and uncertainties, different from or in addition to those we face in our domestic operations.
We conduct our operations in British Columbia through a wholly owned subsidiary, Hudson’s Hope Gas, Ltd. Our operations in British Columbia may be adversely affected by currency fluctuations. The expenses of such operations are payable in Canadian dollars. As a result, our Canadian operations are subject to risk of fluctuations in the relative value of the Canadian and U.S. dollars. Other risks of operations in Canada include, among other things, increases in taxes and governmental royalties and changes in laws and policies governing operations of foreign-based companies. Laws and policies of the U.S. affecting foreign trade and taxation may also adversely affect our operations in British Columbia.
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 attract 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 have not entered into employment nor severance agreements with any of our key employees, other than J. Darby Seré, our President and Chief Executive Officer, William C. Rankin, our Executive Vice President and Chief Financial Officer, and Tony Oviedo, our Vice President, Chief Accounting Officer and Controller. 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 attract, motivate, and retain additional qualified managerial and operations personnel. Competition for these types of personnel is intense, and we may not be successful in attracting, assimilating, and 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 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 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.
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.
The availability or high cost of drilling rigs, equipment, supplies, personnel, and field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
Our industry is cyclical, and from time to time there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs and delivery times of rigs, equipment, and supplies are substantially greater. As a result of historically strong prices of gas, the demand for field services has risen, and the costs of these services are increasing. If the availability or high cost of drilling rigs, equipment, supplies, or qualified personnel were particularly severe in the areas where we operate, we could be materially and adversely affected.
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.
Risks Related to Our Capital Stock
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 majority of the holders of the Preferred Stock, which could limit our ability to access the capital markets.
In connection with the amendment of the terms of our Preferred Stock to revise the anti-dilution provisions of the Preferred Stock to eliminate the treatment of the conversion feature of our Preferred Stock as a derivative liability, we agreed not to 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 majority of the outstanding shares of Preferred Stock, for so long as at least 750,000 shares of
Preferred Stock remain outstanding. This provision may prevent us from issuing common stock or securities convertible into our common stock at a time when the market price of our common stock is less than the conversion price, which could adversely affect our liquidity and results of operations.
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 could limit your ability to influence the outcome of stockholder votes.
Sherwood Energy, LLC beneficially owns approximately 26% of our common stock outstanding as of December 31, 2010 (after giving effect to the conversion of the Series A Convertible Redeemable Preferred Stock held by Sherwood) and Yorktown Energy Partners IV, L.P. beneficially owns approximately 20% of our common stock. Additional shares of our Series A Convertible Redeemable Preferred Stock may be issued to Sherwood and our other Series A preferred stockholders as paid-in-kind 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 common stockholders. 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, 2010, 39,758,484 shares of common stock are outstanding, and 31,911,830 shares of common stock are issuable upon conversion of outstanding Series A Convertible Redeemable Preferred Stock. An additional 3,253,294 shares, net of accrued PIK dividends, of our Series A preferred stock, convertible into 25,025,339 shares of common stock, are reserved for issuance and some or all of that amount may be issued to our preferred stockholders as paid-in-kind, or 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 common stockholders.
Future sales of our common stock by our existing stockholders may depress our stock price.
As of December 31, 2010, 39,758,484 shares of our common stock were outstanding, together with outstanding options representing the right to purchase up to 2,542,159 shares. On September 14, 2010, we issued and sold 2,351,801 shares of our Series A Convertible Redeemable Preferred Stock to Sherwood Energy, LLC and agreed to register the shares of underlying common stock, presently 18,090,776 shares, for resale. In addition, on September 14, 2010 we issued and sold 1,648,199 shares of our Series A Convertible Redeemable Preferred Stock to participants in a registered rights offering. As of December 31, 2010, our outstanding Series A Convertible Redeemable Preferred Stock is convertible into an aggregate of 31,911,830 shares of our common stock, which represents approximately 80% of our issued and outstanding common stock as of December 31, 2010. Upon the effectiveness the resale registration statement relating to the common stock underlying shares of Series A Convertible Redeemable Preferred Stock held by Sherwood, much of the common stock underlying the Series A preferred stock may be sold by the selling security holders in market transactions from time to time. 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 outstanding revolving bank credit agreement contains covenants that restrict 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.
We may not be able to maintain compliance with NASDAQ’s continued listing requirements.
We must comply with NASDAQ’s continued listing requirements in order to maintain our listing on NASDAQ’s Global Market. These continued listing standards include requirements addressing the number of shares publicly held, market value of publicly held shares, stockholder’s equity, number of round lot holders, and a $1.00 minimum closing bid price. If a company’s closing bid price is below $1.00 for 30 consecutive trading days, it receives a notice from NASDAQ that it will be subject to delisting if it fails to regain compliance within 180 days following the date of the notice letter by maintaining a minimum bid closing price of at least $1.00 for ten consecutive business days. If the closing bid price for our common stock is below $1.00 per share for 30 consecutive days or if we in the future fail to meet the other requirements for continued listing on the NASDAQ Global Market, then our common stock could be delisted.
The delisting of our common stock would adversely affect the market liquidity for our common stock, the per share price of our common stock and impair our ability to raise capital that may be needed for future operations.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 3.
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 cannot be predicted with certainty, management does not believe that the adverse effect on our financial condition, results of operations or cash flows, if any, will be material.
EQT Production Company Claim
In March 2011, we received a letter from EQT Production Company (“EQT”) stating that our fracturing operations in 2010 had damaged a well owned by EQT, and demanding the payment of the value of the well and other amounts totaling approximately $430,000. In April 2011, EQT revised their demand for payment to approximately $464,000. We are reviewing the claim to determine if we are liable for the damages alleged to have been sustained by EQT. We believe that if we are responsible for the damages, substantially all of the loss will be covered by our insurance. A majority of our proved undeveloped locations in the Pond Creek field are owned by us through a farmout agreement with EQT that provides that if we default under the agreement, our future development rights under the farmout agreement terminate. The failure to pay the amount of any damages to EQT for which we are liable may be a default as defined in the farmout agreement. We do not believe that the payment of any damages to EQT for which we may be liable will have a material impact on our results of operations, financial position nor cash flows.
Environmental and Regulatory
As of December 31, 2010, 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.
Item 4. [Removed and Reserved]
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock
Our common stock is listed on the NASDAQ Global Market under the symbol “GMET”. The table below shows the high and low closing prices of our common stock for the periods indicated.
Approximately 1,500 stockholders of record as of March 1, 2011 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 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 expansion of our natural gas exploration business. Our revolving credit facility prohibits us from paying any cash dividends.
Preferred Stock
On September 14, 2010, the Company issued and sold 4,000,000 shares of Series A Convertible Redeemable Preferred Stock (“Preferred Stock”), par value $0.001 per share, at a price of $10.00 per share, pursuant to a rights offering (“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 December 31, 2010 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. The applicable annual rate for paid-in-kind dividends (“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. The Company’s revolving credit agreement contains a restrictive covenant which influences its ability to pay cash dividends. Cash dividends are permitted only if the Company’s ratio of debt-to-trailing twelve-month EBITDA, as defined in the revolving credit agreement and after giving effect to such cash dividend payment, is 3.5 to 1.0 or less.
Investor Board Representation
In connection with the Rights Offering, Sherwood Energy LLC (“Sherwood”) entered into a Backstop Commitment to purchase any Preferred Stock not acquired by our stockholders in the Rights Offering. Pursuant to the Backstop Commitment, Sherwood acquired 2,351,801 shares of our Preferred Stock, or 59% of the 4,000,000 shares purchased in the Right Offering. For as long as Sherwood beneficially owns more than 40% of the shares Sherwood acquires pursuant to its Backstop Commitment or otherwise, or beneficially owns 10% or more of our common stock on an as-converted basis, Sherwood will be entitled to nominate two persons to serve on our board.
Board Committees
For as long as Sherwood beneficially owns more than 40% of the shares acquired in the Rights Offering, or beneficially owns 5% or more of our common stock on an as-converted basis, Sherwood will be entitled to nominate one person to serve on our board. Additionally, for such time that Sherwood has the right to nominate at least one director to our board, one member of each of the Audit Committee and the Compensation Committee will be a director nominated by Sherwood, provided that such person(s) meets the applicable independence requirements. We will recommend to our stockholders to vote for the Sherwood nominee(s) and use commercially reasonable efforts to solicit proxies from our stockholders to vote in favor of the Sherwood nominee(s).
Special Voting Rights
In the event of a default under the investment agreement, which includes a default of our obligations under our credit facility or our failure to pay dividends on the preferred stock, the board will be expanded and Sherwood will be allowed to appoint additional directors or we will secure the resignations of directors not appointed by Sherwood, such that Sherwood nominees will constitute a majority of the members of our board. Upon the cure or waiver of the event of default, as applicable, our board will be reduced to the size immediately preceding the default, and the Sherwood directors appointed in connection with the expansion will resign. If we are unable to effectuate an expansion or reconfiguration of our board, or if an event of default continues for more than twelve months, Sherwood may cause us to redeem all of Sherwood’s shares of preferred stock (including PIK dividends) at the redemption price of $10.00 per share plus any unpaid dividends.
Matters Requiring Investor Director Approval
As long as Sherwood continues to beneficially own 40% or more of the shares of Preferred Stock Sherwood acquired in the Rights Offering, or continues to beneficially own 5% or more of our common stock on an as-converted basis, we shall not take any of the following actions without the approval of all of the Sherwood-nominated director(s):
•
incur any new indebtedness for borrowed money or capital leases (excluding borrowings pursuant to our credit facility) in a single transaction in excess of $500,000 within any twelve-month period;
•
authorize or issue equity securities that are senior or pari passu to the preferred stock or convertible into equity securities that are senior or pari passu to the preferred stock;
•
redeem or repurchase equity securities;
•
enter into or be a party to a transaction with any of our directors, officers or employees, any associate of such persons, or any related party that requires disclosure under Item 404(a) of Regulation S-K;
•
liquidate, dissolve or wind-up its affairs, or effect any business combination;
•
enter into a merger, consolidation or restructuring, transfer of assets or other business combination, sale of capital stock, tender offer, exchange offer, recapitalization or other similar transaction that if consummated would result in a person acquiring beneficial ownership of 50% or more of the voting power of the Company or all or substantially all of the consolidated total assets of the Company;
•
appoint a new Chief Executive Officer and/or President;
•
make any alteration or change in the right, preferences or privileges of the preferred stock or increase or decrease the number of authorized shares of preferred stock;
•
amend or waive any provision of our Certificate of Incorporation, our Bylaws, or the Certificate of Designations that adversely affects the rights of the preferred stock; or
•
make any material change in our business from the exploration, exploitation, development and production of oil and natural gas and related activities.
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 2010. On September 14, 2010, the Company issued and sold 4,000,000 shares of Preferred Stock. After paying transaction fees and expenses in the amount of $2.8 million, the Company used the net proceeds of approximately $37.2 million to reduce outstanding bank debt. 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”. For more discussion related to the Preferred Stock, see “Completion of Rights Offering and Backstop Transaction” in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
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, 2010.
(1) A total of 4,000,000 shares of our common stock were reserved for awards to be granted under the GeoMet, Inc. 2006 Long-Term Incentive Plan, which was originally adopted and approved by our stockholders in 2006 and amended in 2009 and 2010. In conjunction with the original approval of the 2006 Plan, no additional awards will be granted under our 2005 Plan; however, we will continue to issue shares of our common stock upon exercise of awards that were previously granted. The 1,432,392 shares of common stock available for future issuance does not include 242,448 shares that were reserved but not granted under our 2005 Plan.
Option Exchange
On December 7, 2010, the Company offered eligible employees the opportunity to exchange certain outstanding stock options for a number of new restricted shares of GeoMet common stock (“Restricted Stock”), to be granted under the GeoMet, Inc. 2006 Long-Term Incentive Plan (the “2006 Plan”).
Options eligible for exchange, or eligible options, were those options, whether vested or unvested, that met all of the following requirements:
•
the options had a per share exercise price greater than $5.00;
•
the options were granted under one of our existing equity incentive plans;
•
the options were outstanding and unexercised as of January 5, 2010;
•
the options were not granted within the twelve-month period immediately preceding the commencement of the offer; and
•
the options did not have a remaining term of less than 12 months immediately following January 5, 2010.
On January 5, 2011, the Company issued 98,416 shares of restricted stock to employees tendering eligible options as follows:
Performance Graph
The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that we specifically incorporate the performance graph by reference into such filing.
The following graph compares the cumulative total stockholder return on our common stock from July 28, 2006, the date our common stock was listed on the Nasdaq Global Market, through December 31, 2010 and compares it with the cumulative total return on the Russell 2000 and the S&P Oil and Gas Exploration and Production Index. The comparison assumes $100 was invested on July 28, 2006 and assumes reinvestment of dividends, if any. The comparisons in this table are not intended to forecast or be indicative of possible future performance of our stock.
COMPARISON OF CUMULATIVE TOTAL RETURN
Item 6.
Item 6. Selected Financial Data
The following table shows our selected historical consolidated financial and operating data as of and for each of the last five years ended December 31, 2010. The selected historical financial data as of December 31, 2010 and 2009 and for each of the three years in the period ended December 31, 2010 are derived from our consolidated audited financial statements included herein. The selected historical financial data as of December 31, 2008, 2007 and 2006 and for each of the two years in the period ended December 31, 2007 was derived from our consolidated audited financial statements which are not included herein. The table reflects a four-for-one common stock split in 2006. You should read the following data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated audited financial statements and related notes included elsewhere in this annual report where there is additional disclosure regarding the information in the following table. Our historical results are not necessarily indicative of the results that may be expected in future periods.
(1) Working capital (deficit) is defined as current assets less current liabilities.
(2) Average realized price includes the effects of realized gains and losses on derivative contracts.
(3) Based on the reserve reports prepared by D&M, independent petroleum engineers, at each period end. Natural gas prices are volatile and may fluctuate widely affecting significantly the calculation of estimated net cash flows. Refer to “Risk Factors” for a more complete discussion.
Item 7.
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, Inc. is an independent energy company primarily engaged in the exploration for and development and production of natural gas from coal seams (“coalbed methane” or “CBM”) and non-conventional shallow gas. We were originally founded as a consulting company to the coalbed methane industry in 1985 and have been active as an operator and developer of coalbed methane properties since 1993. Our principal operations and producing properties are located in the Cahaba Basin in Alabama and the central Appalachian Basin in West Virginia and Virginia. We also own additional coalbed methane and oil and gas development rights, principally in Alabama, British Columbia, Virginia, and West Virginia. As of December 31, 2010, we own a total of approximately 160,000 net acres of coalbed methane and oil and gas development rights.
Our ability to successfully leverage our competitive strengths and execute our strategy depends upon many factors and is subject to a variety of risks. For example, our ability to drill on our properties and fund our capital budgets may depend, to a large extent, upon our ability to generate cash flow from operations at or above current levels, maintain borrowing capacity at or near current levels under our revolving credit facility, and the availability of future debt and equity financing on satisfactory terms. Our ability to fund new opportunities and compete for and retain the qualified personnel necessary to conduct our business is also dependent upon our financial resources. Prolonged weakness in the global economy and in natural gas prices, which may affect both our cash flows and the value of our gas reserves, limitations on our ability to replace production through drilling activities, a material adverse change in our gas reserves due to factors other than changes in gas prices changes, our ability to transport our gas to markets, drilling costs, lower than expected production rates and other factors, many of which are beyond our control, may adversely affect our ability to fund our anticipated capital expenditures, pursue property acquisitions, and compete for qualified personnel, among other things.
Changes in natural gas prices may significantly affect our revenues, financial condition, cash flows, natural gas reserves and borrowing capacity. Markets for natural gas have historically been volatile and we expect this trend to continue. Prices for natural gas may fluctuate in response to changes in supply and demand, market uncertainty, seasonal, political and other factors beyond our control. We are unable to accurately predict the prices we will receive for our natural gas. Accordingly, any significant or sustained declines in natural gas prices may materially adversely affect our financial condition, operating results, liquidity and ability to obtain financing. Declining or prolonged low natural gas prices may also result in non-compliance with the covenants in our revolving credit facility agreement and could result in a lower determination of our borrowing base. Although we will attempt to cure any non-compliance with covenants in our revolving credit facility in the event they occur, no assurance can be given that we will be able to cure such non-compliance. Lower natural gas prices also may reduce the amount of natural gas that we can produce economically. Further declines in natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our proved natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Our capital expenditure budgets are highly dependent on future natural gas prices.
Current Business Plan
In the current natural gas pricing environment, the Company intends to limit capital spending to its internally generated cash flows from operations. Accordingly, it is unlikely to consider any significant exploration activities until conditions improve, as such investments would likely not be economical. We currently intend to drill our proved undeveloped locations in the Pond Creek field and to continue to conduct hydraulic fracturing in new infill wells or in behind pipe shallow zones in the Gurnee field on a limited basis. Our current focus is to complete the developmental drilling program in the Pond Creek field and, in the Gurnee
field, improve production and determine the commerciality of future development through hydraulic fracturing techniques. At current gas prices, it is unlikely that we would seek, nor could we obtain on reasonable terms, significant additional financing necessary to acquire additional properties or otherwise expand beyond our current developmental drilling and hydraulic fracturing programs. At December 31, 2009 and 2010, we had $15.5 million and $9.5 million, respectively, in available borrowing capacity. This business plan is consistent with our past actions taken in unfavorable pricing environments. For example, when the price of natural gas declined precipitously at the end of 2008, we stopped substantially all of our development activities, and in 2009 did not drill any new wells.
Completion of Rights Offering and Backstop Transaction
On September 14, 2010, the Company issued and sold 4,000,000 shares of Series A Convertible Redeemable Preferred Stock at $10.00 per share. After paying transaction fees and expenses in the amount of $2.8 million, the Company used the net proceeds of approximately $37.2 million to reduce outstanding bank debt. The Preferred Stock is senior to our common stock as to payment of dividends and distributions upon liquidation. See “Liquidity and Capital Resources-Completion of Rights Offering and Backstop Transaction” for additional information.
NASDAQ Deficiency Letter
On September 28, 2010, the Company received a deficiency letter from the staff of The NASDAQ Stock Market, advising the Company that, for the previous 30 consecutive business days, the bid price for the Company’s common stock had closed below the minimum $1.00 per share required under NASDAQ Marketplace Rule 5450(a)(1) for continued listing on the NASDAQ Global Market. The notification letter stated that the Company was afforded 180 calendar days to regain compliance with the minimum bid price requirement. On January 5, 2011, the Company received notice from The NASDAQ Stock Market that it has regained compliance with the minimum $1.00 bid price per share required under NASDAQ Marketplace Rule 5450(a)(1) and, as such, is in compliance for continued listing on the NASDAQ Global Market.
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 2 to our consolidated audited 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 D&M, independent petroleum engineers.
Gas Properties-The method of accounting for 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 gas properties as prescribed by the United States Securities and Exchange Commission (“SEC”). Under this method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our gas properties are capitalized and segregated into U.S. and Canadian cost centers.
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 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. The ceiling test is imposed separately for our U.S. and Canadian cost centers. 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 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.
Unevaluated Properties-The costs directly associated with unevaluated properties and properties under development are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination of proved reserves together with overhead and interest costs capitalized for these projects. Unevaluated leasehold costs are transferred to the amortization base once determination has been made or upon expiration of a lease. Geological and geophysical costs associated with a specific unevaluated property are transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. All items included in our unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value. Any impairment to unevaluated properties is transferred to the amortization base.
Asset Retirement Liability-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 liability, 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 useful life of the related asset.
Income Taxes-We record our income taxes using an asset and liability approach in accordance with the provisions of ASC 740, formerly SFAS No. 109, Accounting for Income Taxes. 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.
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.
Deferred Tax Asset Recoverability
Our total net deferred tax asset at December 31, 2010 was $46.0 million, which includes a valuation allowance of $3.1 million. Our valuation allowance primarily relates to our Canadian operations where we do not believe it is more likely than not that we will recover our net deferred tax asset prior to expiration as well as certain immaterial state net operating losses where the Company has ceased operations. In evaluating the need for a valuation allowance, we considered the fact that we have recorded a cumulative, pretax loss of $277.3 over the past three years. This cumulative loss was the result of the Company incurring a total of $308 million in full cost ceiling test impairments during 2009 and the fourth quarter of 2008. Relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income may be insufficient to overcome a history of such losses. In developing our forecasts as to whether our net deferred tax asset would more likely than not be recovered, we considered the fact that there were no ceiling test impairments in 2010, as well as the fact that the situation that contributed to the impairments was the unprecedented economic downtown which began in the fourth quarter of 2008 and resulted in the price of natural gas falling from a high of $13.32 in the third quarter of 2008 to a low of $5.38 in the fourth quarter of 2008 and to a further low of $1.85 in the third quarter of 2009. In addition, we considered the fact that the current remaining capitalized costs plus planned future costs are significantly less than the historical ceiling test impairments and it is expected that future production will produce sufficient taxable income to cover these costs.
Our first material net operating loss (“NOL”) carryforward expires in 2022 and the last one expires in 2030. We also consider the lengthy carryforward period in the overall evaluation of our ability to realize our NOLs as it substantially increases the likelihood of utilization.
In order to test our net deferred tax asset for recoverability, we performed a historical based analysis by using our cumulative three-year historical book loss and added back the historical book impairment and book depletion. We used this three-year historical average taxable income before tax depletion and intangible drilling cost amortization to project taxable income for the next 20 years, which corresponds to our NOL carry forward period. We then reduced the total by the remaining book basis of our gas properties and projected future book basis. In this analysis, our net deferred tax assets including all NOLs will be utilized prior to expiration. We believe this analysis provides significant positive evidence that is objectively verifiable, as it uses three-year historical operating results to predict future taxable income. We have considered all applicable tax deductions in this analysis which are substantially known and are not subject to significant estimates.
In addition, we performed a forecast based analysis based on inputs from third party sources. Our primary inputs for this analysis come from our reserve report that is estimated and appraised by an independent third party engineer as well as future market pricing as determined by the New York Mercantile Exchange. To test the sensitivity of the forecast, we adjusted several assumptions, including, but not limited to, the following: use of three-year historical average production, use of three-year average pricing, and use of three-year average margins. Under all scenarios, we generate sufficient taxable income to fully realize the net deferred tax asset prior to expiration.
The Company will continue to assess the need for a valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods. If our assumptions regarding forecasted production, pricing, and margins are not achieved by amounts in excess of our sensitivity analysis, it may have a significant impact on the corresponding taxable income which may require a valuation allowance to be recorded against our then existing deferred tax assets.
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 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. We typically do not have any significant producer gas imbalance positions because we own 100% working interest in the majority of our properties. 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. Pipeline imbalances are settled with cash approximately thirty days after the month of production and are recorded as a reduction of revenue 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 to hedge against changes in natural gas prices and changes in interest rates related to outstanding debt under our credit facility primarily through the use of fixed price swap agreements, basis swap agreements, three-way collars, and traditional collars. Consistent with our hedging policy, we entered into a series of derivative instruments to hedge a significant portion of our expected natural gas production through 2013. We also entered into an interest rate swap agreement to hedge interest rates associated with a portion of our variable rate debt through 2011. 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 consolidated audited financial statements in accordance with ASC 815, formerly SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Although not risk free, we believe this policy will reduce our exposure to natural gas price fluctuations and changes in interest rates 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.
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 or other comprehensive income (loss) for our interest rate swaps. The natural gas derivatives have not been designated as hedge transactions while the interest rate swaps qualify and have been designated as such in accordance with ASC 815-20-25.
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 hedge 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.
Mezzanine Equity /Embedded Derivative-Our Series A Convertible Redeemable 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. In addition, we evaluated the conversion feature and determined that because of certain anti-dilution provisions, the conversion feature was not indexed to our stock and as such, the holder’s conversion option was to be separated and recorded at fair value as a derivative liability. Subsequent changes in the fair value of the derivative liability were recorded as a component of other income and expense in the Consolidated Statements of Operations.
The fair value of the derivative liability attributable to the conversion option was determined using an American binomial lattice model, which utilized assumptions including 80% volatility, a 17% discount factor and an expected term of 6.4 years determined using a Monte Carlo simulation model. For the year ended December 31, 2010, the Company recorded approximately $2.1 million to Unrealized loss from change in fair value of derivative liability-Series A Convertible Redeemable Preferred Stock in the Consolidated Statements of Operations as a result of the change in the fair value of the derivative liability. On December 21, 2010, the Company amended the terms of the Preferred Stock to adjust the anti-dilution provision and further limit the Company’s ability to issue junior securities (including additional shares of common stock), at a price lower than the current conversion price, without the consent of holders of a majority of shares of Series A Preferred Stock. After the amendment, the conversion feature is indexed to our stock and as such, is no longer required to be accounted for as a derivative. On the effective date of the Amendment, the bifurcated derivative liability on the Company’s consolidated balance sheet related to the conversion feature was reclassified to paid-in capital on the Company’s consolidated statements of stockholders’ equity and comprehensive income (loss).
Fair Value Measurement-Effective January 1, 2008, we adopted ASC 820-10-55, formerly SFAS No. 157, Fair Value Measurements, 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 related to the implementation of ASC 820-10-55 in Note 8-Derivative Instruments and Hedging Activities. The FASB has also issued Staff Position FAS 157-2 (“FSP 157-2”), which delays the effective date of ASC 820-10-55 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. We have elected to defer the application of ASC 820-10-55 thereof to nonfinancial assets and liabilities in accordance with FSP 157-2. Non-recurring nonfinancial assets and nonfinancial liabilities for which the Company has not applied the provisions of ASC 820-10-55 include those measured at fair value in goodwill impairment testing, asset retirement obligations initially measured at fair value, and those initially measured at fair value in a business combination. On October 10, 2008, the FASB issued Staff Position No. FAS 157-3 (“FSP 157-3”). FSP 157-3 clarifies the application of ASC 820-10-55 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not
active. On January 1, 2009, we adopted ASC 820-10-55 as it relates to nonfinancial assets and liabilities, including nonfinancial assets and liabilities measured at fair value in a business combination; impaired property, plant and equipment; goodwill; and initial recognition of asset retirement obligations. There has been no significant impact to our consolidated audited financial statements related to the implementation of ASC 820-10-55 for our existing non-financial assets and liabilities.
Stock-Based Compensation-We follow the fair value recognition provisions of ASC 718, formerly SFAS No. 123(R), Share-Based Payment. 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.
Natural Gas Producing Fields Operations Summary
The table below presents information on gas revenues, sales volumes, production expenses and per Mcf data for the years ended December 31, 2010, 2009 and 2008. This table should be read with the discussion of the results of operations for the periods presented below.
(1) Average realized price includes the effects of realized gains and losses on derivative contracts.
The following table presents certain information with respect to our production and operating data for each of the three month periods in the year ended December 31, 2010.
(1) Average realized price includes the effects of realized gains and losses on derivative contracts.
Results of Operations
Year Ended December 31, 2010 compared with Year Ended December 31, 2009
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 increased by $2.5 million, or 8%, to $33.1 million compared to the prior year. The increase in gas sales was a result of higher natural gas prices, which increased approximately 11% excluding hedging transactions, partially offset by a 2.5% decrease related to production. The decrease related to production was principally attributable to the normal production declines with no drilling in 2009 to offset such normal production declines.
Lease operating expenses. Lease operating expenses decreased by $2.4 million, or 17%, to $11.5 million compared to the prior year. The $2.4 million decrease in lease operating expenses consisted of $2.0 million decrease in costs and a $0.4 million decrease related to production. The $2.0 million decrease in costs was primarily due to a company-wide cost reduction strategy implemented in April 2009.
Compression expense. Compression expense decreased by $0.5 million, or 14%, to $2.9 million compared to the same period in the prior year. The $0.5 million decrease was comprised of $0.4 million decrease in costs and a $0.1 million decrease related to production. The $0.4 million decrease in costs was primarily due to a company-wide cost reduction strategy implemented in April 2009.
Transportation expense. Transportation expense decreased by $0.4 million, or 23%, to $1.3 million compared to the prior year period. The decrease was primarily due to the permanent release of excess transportation capacity effective May 1, 2009.
Production taxes. Production taxes decreased by $0.2 million, or 13%, to $1.0 million compared to the prior year period. The decrease related to production taxes was primarily due to production tax refunds in the current year, partially offset by an increase in production taxes due to the phase-in of state taxes on production of natural gas in the West Virginia portion of our Pond Creek field.
Depreciation, depletion and amortization. Depreciation, depletion and amortization decreased by $5.7 million, or 48%, to $6.3 million compared to the prior year period. The depreciation, depletion and amortization decrease consisted of a $0.3 million decrease related to production and a $5.4 million decrease in the depletion rate. The decrease in the depletion rate was due to the ceiling write-downs incurred throughout 2009.
Impairment of gas properties. During 2010, the carrying value of the Company’s gas properties did not exceed the full cost ceiling limitation. As such, there was no such impairment recorded in 2010.
General and administrative. General and administrative expenses decreased by $3.0 million, or 36%, to $5.4 million compared to the prior year period. The decrease in general and administrative expenses was primarily due to a company-wide cost reduction strategy implemented in April 2009.
Terminated transaction costs. During the current year, we incurred $1.3 million of costs related to a proposed financing transaction with certain parties and $0.1 million related to a potential sale of certain assets. Negotiations with those parties ceased and the related costs were expensed as terminated transaction costs. No such expenses were incurred in the prior year.
Realized gains on derivative contracts. Realized gains on derivative contracts decreased by $1.7 million, or 16%, to $9.0 million compared to the prior year. 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 (gains) losses from the change in market value of open derivative contracts. Unrealized gains on open derivative contracts were $6.0 million in the current year period as compared to unrealized losses of $4.0 million in the prior 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.
Interest expense. Interest expense remained materially unchanged compared to the prior year.
Unrealized loss from the change in fair value of derivative liability-Series A convertible Redeemable Preferred Stock. The loss in 2010 was primarily the result of the increase in the market price of our common stock from the issuance date of our Series A Preferred Stock of September 14, 2010 through the effective date of
the amendment to Series A Preferred Stock anti-dilution feature. The Company amended the terms of the anti-dilution provisions of its Preferred Stock on December 21, 2010. The effect of the amendment was to extinguish the liability and reclassify it to paid-in capital. Future changes in the price of our common stock will not result in the recognition of gains or losses attributable to the anti-dilution provisions of our preferred stock.
Income tax expense (benefit). Income tax expense was $5.4 million in the current year as compared to an income tax benefit of $98.1 million in the prior year. The effective tax rate for the current year was 48.3%. Income tax expense for the year ended December 31, 2010 was different than the amount computed using the statutory rate as follows:
Year Ended December 31, 2009 compared with Year Ended December 31, 2008
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 $37.7 million, or 55%, to $30.6 million compared to the prior year. The decrease in gas sales was a result of significantly lower natural gas prices, which decreased approximately 56% excluding hedging transactions, partially offset by increased production, which increased 1%. The increase in production was principally attributable to the prior year development activities at our Pond Creek field and the commencement of gas sales in our Garden City field in July 2008, Lasher field in October 2008, and Peace River in December 2008, partially offset by the sale of an overriding royalty interest that was sold effective July 1, 2008 and decreased current year production in our Gurnee field.
Lease operating expenses. Lease operating expenses decreased by $0.8 million, or 6%, to $13.9 million compared to the prior year. The $0.8 million decrease in lease operating expenses consisted of $1.0 million
decrease in costs, partially offset by a $0.2 million increase in production. The $1.0 million decrease in costs was primarily due to a company-wide cost reduction strategy implemented in April 2009, partially offset by increased expenses related to the commencement of gas sales in our Garden City field in July 2008, Lasher field in October 2008, and Peace River in December 2008.
Compression expense. Compression expense increased by $0.3 million, or 10%, to $3.3 million compared to the same period in the prior year. The increase in compression expense was primarily due to the addition of Peace River compression costs where gas sales commenced on December 31, 2008.
Transportation expense. Transportation expense increased by $0.2 million, or 15%, to $1.7 million compared to the prior year period. The increase was primarily due to the fact that a greater amount of excess capacity was released in the prior year period effectively reducing transportation expense for that period. The excess transportation capacity that caused the increase was permanently released in May 2009. As a result of this permanent release, we expect to incur less transportation costs in the future.
Production taxes. Production taxes decreased by $1.0 million, or 45%, to $1.2 million compared to the prior year period. The decrease related to production taxes was primarily due to decreased natural gas sales caused by lower natural gas prices.
Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $1.4 million, or 14%, to $12.0 million compared to the prior year period. The depreciation, depletion and amortization increase consisted of $3.9 million in accelerated depletion caused by estimated natural gas reserve revisions recorded as of September 30, 2009, offset by a $2.5 million decrease due to the decrease in the depletion rate resulting from our ceiling write-downs incurred to-date.
Impairment of gas properties. For the year ended December 31, 2009, impairments recorded to gas properties were $159.7 million, net of tax benefit of $97.6 million. These impairments were caused by lower natural gas prices, as well as downward reserve revisions due in large part to continued under-performance in the Gurnee field. We were able to limit the effect of lower natural gas prices through our ongoing cost reduction strategy, which we implemented in April 2009.
General and administrative. General and administrative expenses decreased by $1.0 million, or 11%, to $8.3 million compared to the prior year period. The primary driver of the decrease in general and administrative expenses was the cost reduction strategy implemented in April 2009, offset by $0.8 million less capitalized overhead as a result of decreased drilling activities.
Realized (gains) losses on derivative contracts. Realized gains on derivative contracts were $10.7 million in the current year period as compared to realized losses of $0.5 million in the prior year period. 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 (gains) from the change in market value of open derivative contracts. Unrealized losses on open derivative contracts were $4.0 million in the current year period as compared to unrealized gains of $5.0 million in the prior year period. Unrealized losses and gains 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.
Interest expense. Interest expense increased by $0.4 million, or 8%, to $5.2 million compared to the prior year period. The increase is due to the effect of a higher average outstanding debt balance in the current year period, partially offset by a lower average interest rate in the current year period. Additionally, the prior year included $0.3 million of capitalized interest for which there was no comparable capitalized interest in the current year period as a result of no drilling activity.
Income tax benefit. Income tax benefit was $98.1 million in the current year as compared to $0.7 million in the prior year. The increased benefit was primarily the result of the impairments recorded to gas properties of $159.7 million, net of tax benefit of $97.6 million. These impairments were caused by lower natural gas prices, as well as downward revisions due in large part to continued under-performance in the Gurnee field. We were able to limit the effect of lower natural gas prices through our ongoing cost reduction strategy, which we implemented in April 2009. The effective tax rate for the period was 37.0%. Income tax benefit for the year ended December 31, 2009 was different than the amount computed using the statutory rate as follows:
Liquidity and Capital Resources
Cash Flows and Liquidity
Cash flows provided by operations for the years ended December 31, 2010, 2009 and 2008 were $16.0 million, $8.5 million and $33.0 million, respectively. As of December 31, 2010, we had working capital of approximately $1.5 million. As of December 31, 2009, we had a working capital deficit of less than $0.1 million. We believe that our cash flow from operations and other financial resources such as borrowings under our revolving credit facility will provide us with sufficient capital resources to meet our projected capital expenditures for the next twelve months.
Revolving Credit Facility
On September 14, 2010, our Fourth Amended and Restated Credit Agreement (the “Credit Agreement”) with a group of five banks became effective. The Credit Agreement replaced our Third Amended and Restated Credit Agreement and provides for revolving credit borrowings of up to $180 million with an initial borrowing base of $90 million. The borrowing base will be determined as of each June and December with the next determination scheduled to be completed by June 2011. All outstanding borrowings under the Credit Agreement become due and payable on September 14, 2013. The Credit Agreement provides for interest to accrue at a rate calculated, at the Company’s option, at the Adjusted Base Rate plus a margin of 1.75% to 2.25% or the London Interbank Offered Rate (the “LIBOR Rate”) rate plus a margin of 2.75% to 3.25%. 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%). In all cases the applicable margin is dependent on the percentage of borrowing base usage. Under the Credit Agreement we are subject to certain financial covenants requiring maintenance of (i) a minimum Current Ratio, (ii) a maximum Debt Ratio and, (iii) depending on our Debt Ratio, either (a) a minimum Interest Coverage Ratio or (b) a minimum Fixed Charge Ratio. The Current Ratio of consolidated current assets (defined to include amounts available under our borrowing base) to consolidated current liabilities (defined to exclude up to $1.5 million in accrued and unpaid preferred dividends) is not permitted to be less than 1.0 to 1.0 as of the end of any fiscal quarter. At December 31, 2010, the Current Ratio, as defined, was 1.32. The Debt Ratio (defined as funded debt at the end of each fiscal quarter to trailing four quarter consolidated EBITDA) at the end of each fiscal quarter cannot exceed 4.5 to 1.0 through the quarter ending June 30, 2011 and 4.0 to 1.0 thereafter. At December 31, 2010, the Debt Ratio, as defined, was 3.46. If our Debt Ratio at the end of each fiscal quarter is above 3.5 to 1.0, then the Fixed Charge Ratio (defined as consolidated EBITDA less capital expenditures to consolidated net cash interest expense for the four preceding quarters) is applicable and cannot be less than 1.25 to 1.0. At December 31, 2010, the Fixed Charge Ratio, as
defined, was 2.06. If our Debt Ratio at the end of each fiscal quarter is 3.5 to 1.0 or less, the Interest Coverage Ratio (defined as consolidated EBITDA to consolidated net cash interest expense plus letter of credit fees accruing during the preceding four quarters) is applicable and cannot be less than 2.75. At December 31, 2010, the Fixed Charge Ratio, as defined, was 5.07. Consolidated EBITDA is defined as earnings (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization and also excludes non-recurring charges and other non-cash charges deducted in determining net income (loss), which would include unrealized gains and losses from a change in the market value of open derivative contracts. The Company expects continued compliance with the aforementioned covenant in the near term.
We are also subject to covenants restricting or prohibiting cash dividends and other restricted payments, transactions with affiliates, incurrence of debt, consolidations and mergers, the level of operating leases, assets sales, investments in other entities, and liens on properties. Cash dividends on our preferred stock are permitted if, following any such cash payment our availability is equal to or greater than 15% of the then current borrowing base and our Debt Ratio is less than 3.5 to 1.0. There are no restrictions associated with the payment of PIK dividends on our preferred stock.
Completion of Rights Offering and Backstop Transaction
On September 14, 2010, the Company issued and sold 4,000,000 shares of Series A Convertible Redeemable Preferred Stock (“Preferred Stock”), par value $0.001 per share, at a price of $10.00 per share. After paying transaction fees and expenses in the amount of $2.8 million, the Company used the net proceeds of approximately $37.2 million to reduce outstanding bank debt. The Preferred Stock ranks senior to our common stock as to payment of dividends and distribution upon liquidation.
Dividends accrue quarterly on the Preferred Stock, including any Preferred Stock issued as paid-in-kind dividends (“PIK dividends”), which in our sole discretion, may be paid in any combination of cash, or, until the fifth anniversary of the closing of the rights offering, in PIK dividends. The applicable annual rate for dividends paid in cash is 8.0% for the first three years and 9.6% thereafter. The applicable annual rate for PIK dividends is 12.5%. All dividends are cumulative and all unpaid dividends compound on a quarterly basis at a 12.5% annual rate. At December 31, 2010, an additional 3,253,294 shares of our Preferred Stock are reserved exclusively for the payment of PIK dividends.
The Preferred Stock is immediately convertible into common stock, at the sole option of the holder, at an initial conversion price of $1.30 per common share (as it may be adjusted from time to time, the “Conversion Price”). The Preferred Stock converts into a number of shares of common stock determined by dividing (i) the sum of (A) $10.00 plus (B) accrued but unpaid dividends by (ii) the Conversion Price. At the current Conversion Price, up to an additional 31,911,830 shares of our common stock would be outstanding immediately after conversion of our Preferred Stock. The Conversion Price and resulting number of shares of common stock issued upon conversion of Preferred Stock is adjusted to reflect stock splits and similar events and is entitled to anti-dilution adjustments for any dividends paid on common stock in cash or in common stock, the issuance of additional equity securities at a price less than the Conversion Price (excluding shares, rights and options subject to certain employee benefit arrangements), and the occurrence of certain material corporate transactions at a per share valuation less than the Conversion Price.
At any time beginning eight years from the date of issuance, the Preferred Stock is redeemable, in whole or in part, at the sole option of the holder. The purchase price per share, payable in cash, will be equal to the sum of the original purchase price and any accrued and unpaid dividends.
We have the option, beginning three years from the date of issuance, to convert the Preferred Stock into our common stock at the then current Conversion Price, subject to certain volume and other limitations. In order for us to exercise this option, the daily volume-weighted average trading price of our common stock must be greater than 225% of the then current Conversion Price for twenty (20) out of the previous thirty (30) trading days.
The holders of the Preferred Stock are entitled to vote on all matters on which the holders of our common stock are entitled to vote. The holders of the Preferred Stock generally vote together with the holders of the common stock as a single class, with the Preferred Stock holders entitled to the number of votes such holders would have on an as-converted basis. Certain actions also require a separate vote of the Preferred Stock.
Upon the occurrence of a liquidation, dissolution or winding up of the Company resulting in a payment or distribution of assets to the holders of any of our capital stock (each such event, a “Liquidation Event”), the holders of the Preferred Stock (including PIK dividends) are entitled to receive, prior and in preference to any payment, or segregation for payment, of any consideration to any holder of any junior security of the Company, an amount in cash equal to the greater of (i) $10.00 per share, plus any accrued but unpaid dividends (in each case adjusted for any stock dividends, splits, combinations or similar events), or (ii) an amount equal to the amount such holders of the Preferred Stock would have received upon the Liquidation Event if they had converted their shares of Preferred Stock into shares of our common stock.
If not converted, the Preferred Stock (including any PIK dividends) is redeemable by us on or at any time after a Liquidation Event. In the absence of a Liquidation Event, if not converted, a holder of Preferred Stock (including any PIK dividends) may cause us to redeem the Preferred Stock held by such holder, in whole or in part, on or after September 14, 2018, upon 30 days prior written notice to us. Upon any redemption of Preferred Stock by us, as of the effective date of the redemption, we will pay to each holder of Preferred Stock, $10.00 per share of Preferred Stock (including any PIK dividends) held plus any accrued but unpaid dividends (in each case adjusted for any stock dividends, splits, combinations or similar events).
During the year ended December 31, 2010, the Company declared and issued PIK dividends of 148,538 shares to the holders of Preferred Stock.
The 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. The Preferred Stock balance in mezzanine equity will be accreted to its redemption value over the eight year redemption period. In addition, we evaluated the conversion feature at September 14, 2010 and determined that its terms required the holder’s conversion option to be separated and recorded at fair value as a derivative liability on the Consolidated Balance Sheet. Subsequent changes in the fair value of the derivative liability were recorded as a component of other income and expense in the Consolidated Statements of Operations.
The fair value of the derivative liability attributable to the conversion option was determined using an American binomial lattice model, which utilized assumptions including 80% volatility, a 17% discount factor and an expected term of 6.4 years determined using a Monte Carlo simulation model, and resulted in a fair value of approximately $18.4 million on the date of issuance. The remaining net proceeds of $20.4 million were allocated to Series A Convertible Redeemable Preferred Stock in the Consolidated Balance Sheets. For the year ended December 31, 2010, the Company recorded approximately $2.1 million to Unrealized loss from change in fair value of derivative liability-Series A Convertible Redeemable Preferred Stock in the Consolidated Statements of Operations as a result of the change in the fair value of the derivative liability.
On December 21, 2010, the Company amended the terms of the Preferred Stock to adjust the anti-dilution provision and further limit the Company’s ability to issue junior securities (including additional shares of common stock), at a price lower than the current conversion price, without the consent of holders of a majority of shares of Series A Preferred Stock.
The Preferred Stock initially contained an anti-dilution provision that was triggered when the Company issued certain additional common stock or securities convertible into common stock for consideration per share less than the conversion price of the Preferred Stock. The anti-dilution provision was amended during 2010 so that, in the event of such issuance, the conversion price of the Preferred Stock will be reduced to a price determined by multiplying the then-current conversion price by a fraction (a) the numerator of which will be the
sum of (i) the number of shares of common stock outstanding, on a fully diluted basis, before the additional issuance plus (ii) the number of shares of common stock which the aggregate consideration received by the Company for the additional issuance would purchase at the conversion price then in effect, and (b) the denominator of which will be the sum of (x) the number of shares of common stock outstanding before the additional issuance plus (y) the number of such additional shares of common stock that were actually issued.
In addition, the terms of the Preferred Stock was amended to prohibit the Company from issuing 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 Series A Preferred Stock without the prior vote or consent of holders of a majority of the outstanding shares of Series A Preferred Stock, for so long as at least 750,000 shares of Series A Preferred Stock remain outstanding.
We amended the terms of the Preferred Stock because we believed that the valuation, accounting and disclosure obligations associated with the embedded derivative were burdensome and that such accounting treatment did not clearly represent the overall financial condition and results of operations of the Company. Determining the periodic change in the fair value of the derivative liability required a costly valuation each quarter and produced significant volatility in the Company’s consolidated balance sheet and consolidated statement of operations. In addition, the valuation required Level 3 inputs and assumptions, under ASC 820-10-55, for reporting purposes, and was considered a critical accounting area which includes a high degree of judgment and uncertainty.
On the effective date of the Amendment, December 21, 2010, the bifurcated derivative liability on the Company’s consolidated balance sheet related to the conversion feature was reclassified to paid-in capital on the Company’s consolidated statements of stockholders’ equity and comprehensive income (loss). In addition, we will no longer experience the potential volatility on the consolidated balance sheets and consolidated statements of operations from unrealized gains or losses resulting from future fair value fluctuations of the extinguished derivative liability. As a result, we expect our consolidated financial statements to be more consistent with the underlying operations of the Company.
The following table details the activity related to the issuance and accretion of the Series A Convertible Redeemable Preferred Stock and the related derivative liability for the year ended December 31, 2010:
(1) Issuance costs of $2,832,472 were incurred as part of the issuance of the Series A Convertible Redeemable Preferred Stock. As the Series A Convertible Redeemable Preferred Stock was bifurcated on the Consolidated Balance Sheet as disclosed in the table above, $1,531,056 of the issuance costs were allocated to Mezzanine Equity-Series A Convertible Redeemable Preferred Stock. The remaining $1,301,416 of issuance costs were allocated to Other current assets and Other noncurrent assets to be amortized over the term of the Series A Convertible Redeemable Preferred Stock and, as a result of the amendment to the Preferred Stock agreement on December 21, 2010, $1,261,343($1,301,416 of original issuance costs, less $40,073 amortized in 2010) were reclassified to equity.
Capital Expenditures
The following table is a summary of our capital expenditures on an accrual basis by category:
We expect our capital expenditure budget for 2011 to be $13.9 million. The amount and timing of our expenditures are subject to change based upon market conditions, natural gas prices, results of operations and other factors. We routinely adjust our capital expenditure budget in response to changes in natural gas prices, drilling and acquisition costs, cash flow, drilling results and changes in borrowing capacity under our revolving credit facility.
The development of coalbed methane fields requires substantial initial investment before meaningful production and resulting cash flows are realized. Among the factors that can be expected to affect our cash flows and liquidity are the characteristics of the field, the amount of water produced, the methods utilized to dispose of produced water, the transportation alternatives, and the timing and rate of initial and subsequent natural gas production volumes.
Changes in natural gas prices significantly affect our revenues, financial condition, cash flows and borrowing capacity. Markets for natural gas have historically been volatile and we expect this trend to continue. Prices for natural gas may fluctuate in response to changes in supply and demand, market uncertainty, seasonal, political and other factors beyond our control. We are unable to accurately predict the prices we will receive for our natural gas. Accordingly, any significant or sustained declines in natural gas prices will materially adversely affect our financial condition, operating results, liquidity and ability to obtain financing. Continued or prolonged low natural gas prices may also result in non-compliance with the covenants in our revolving credit facility agreement and could result in a lower determination of our borrowing base. Lower natural gas prices also may reduce the amount of natural gas that we can produce economically. Further declines in natural gas prices have a material adverse effect on the estimated value and estimated quantities of our proved natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Our capital expenditure budgets are highly dependent on future natural gas prices.
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 from time to time
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 price movements. Our price risk management policy strictly prohibits the use of derivatives for speculative positions.
We enter 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. We generally limit the amount of these hedges during any period to no more than 50% to 70% of the then expected gas production for such future periods. 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. Three-way costless collars are similar to regular costless collars except that, in order to increase the ceiling price, we agree to limit the amount of the floor price protection (through a sold floor) to a predetermined amount, generally between $2.00 and $3.00 per MMBtu below the bought floor. 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, 2010, we had the following natural gas collar positions:
At December 31, 2010, we had the following natural gas swap positions:
Our production is sold at an “all-in” price which includes the market price for natural gas plus a “basis differential”. In January 2011, we agreed to sell gross volumes of 16,000 MMBtu/day of natural gas from our Pond Creek field for the period February 2011 through March 2012 through a forward physical sale contract with our existing purchaser at a price equal to the last day settlement price for the NYMEX contract for the month of sale plus a basis differential of $0.15, $0.115, and $0.13 for the periods February 2011 through March 2011, April 2011 through October 2011, and November 2011 through March 2012, respectively. Gross sales from the Pond Creek field averaged approximately 17,800 MMBtu/day for the year ended December 31, 2010. As such, the overall delivery agreement represents approximately 90% of the 2010 average gross daily sales. Additionally, we fixed the NYMEX settle on a portion of the aforementioned forward sale as follows:
The remaining volumes giving effect for the fixed amounts denoted above are as follows:
Interest Rate Risks and Related Hedging Activities
When we enter into an interest rate swap, we may designate the derivative as a cash flow hedge, at which time we prepare the documentation required under ASC 815-20-25. Hedges of our interest rate are designated as cash flow hedges based on whether the interest on the underlying debt is converted to a fixed interest rate. Changes in derivative fair values that are designated as cash flow hedges are deferred as other comprehensive income or loss to the extent that they are effective and then recognized in earnings when the hedged transactions occur.
We use fixed rate swaps to limit our exposure to fluctuations in interest rates with the objective of realizing a fixed cash flow stream from these activities. At December 31, 2010, we had the following interest rate swaps:
(1) The floating rate paid by the counterparty is the British Bankers’ Association LIBOR rate.
Contractual Commitments
We have numerous contractual commitments in the ordinary course of business, debt service requirements and operating lease commitments. The following table summarizes these commitments at December 31, 2010, beginning January 1, 2011 (in thousands):
(1) Maturities based on the September 2010 amended bank credit agreement terms, as amended, which extended the maturity date to September 14, 2013.
(2) The outstanding balances on the revolving credit facility bear interest at the Company’s option of either (a) the Adjusted Base Rate, which is the greatest of (i) the agent’s base rate, (ii) the federal funds rate plus 0.5%, or (iii) the LIBOR rate plus a margin of 1%, plus a margin of 1.75% to 2.25%, or (b) the LIBOR rate, plus a margin of 2.75% to 3.25%, based on borrowing base usage. The rate at December 31, 2010, excluding the effect of our interest rate swaps, was 3.30%.
(3) As of December 31, 2010, we had a liability for unrecognized tax benefits of approximately $273,000. We are unable to reliably estimate the timing and amount of any payments related to this liability because there are currently no outstanding unpaid assessments from any tax authority, and it is likely that assessments would be offset by existing deferred tax attributes as they arise.
The following were maturities of long-term debt for each of the next five years at December 31, 2010:
In January 2011, we agreed to sell gross volumes of 16,000 MMBtu/day of natural gas from our Pond Creek field for the period February 2011 through March 2012 through a forward physical sale contract with our existing purchaser at a price equal to the last day settlement price for the NYMEX contract for the month of sale plus $0.15, $0.115, and $0.13 for the periods February 2011 through March 2011, April 2011 through October 2011, and November 2011 through March 2012, respectively. Additionally, we fixed the NYMEX settle on a portion of the aforementioned forward sale as follows: (1) 4,000 MMBtu /day for the period April 2011 through October 2011 was fixed at a total price for physical gas sales, including the aforementioned basis, of $4.915/ MMBtu and (2) 3,000 MMBtu /day for the period November 2011 through March 2012 was fixed at a total price for physical gas sales, including the aforementioned basis, of $5.33/ MMBtu. These contracted volumes represent approximately 89% of total expected gross production volumes for the contract period from the Pond Creek field. If we are unable to fulfill our commitment, or a portion thereof, we are obligated to reimburse our counterparty
for any price paid to replace the quantity of natural gas we failed to deliver which is in excess of the contract price. This obligation is limited to the spot price for natural gas at the delivery point on the day we fail to deliver.
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, 2010 under non-cancelable operating leases having remaining terms in excess of one year are as follows:
Total rental expenses under operating leases were approximately $1,528,739, $1,857,026, and $2,005,994 for the years ended December 31, 2010, 2009 and 2008, respectively.
Transportation Contracts-As of December 31, 2010, 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, and (3) 10,000 MMBtu’s continuing until April 1, 2017. We have a right to extend each of these contracts, in five-year increments, at the maximum tariff rate. As of December 31, 2010, the maximum commitment remaining under the transportation contracts is approximately $12.3 million.
Recent Accounting Pronouncements
In December 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting (“ASC 2010-3”), which amended the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, and added a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which was eliminated. The goal of Release No. 33-8995 is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Companies affected by Release No. 33-8995 are now required to price estimated proved oil and gas reserves using the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. SEC Release No. 33-8995 is effective beginning for financial statements for fiscal years ending on or after December 31, 2009. The Company adopted SEC Release No. 33-8995 effective December 31, 2009. The impact on the Company’s operating results, financial position and cash flows has been recorded in the consolidated audited financial statements and additional disclosures were added to the accompanying notes to the consolidated audited financial statements for the Company’s supplemental oil and gas disclosure. See Supplementary Financial and Operating Information on Gas Exploration, Development and Producing Activities (Unaudited) for the years ended December 31, 2010, 2009 and 2008 for more details.
In January 2010, the Financial Accounting Standards Board (“FASB”) issued FASB Accounting Standards Update (“ASU”) No. 2010-03 Oil and Gas Estimation and Disclosures (“ASU 2010-03”). This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries Oil and Gas topic of the FASB Accounting Standards Codification (“ASC Topic 932”) with the changes required by the SEC final rule ASC 2010-3. As discussed above, ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of
proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. The Company adopted ASU 2010-03 effective December 31, 2009. See Supplementary Financial and Operating Information on Gas Exploration, Development and Producing Activities (Unaudited) for the years ended December 31, 2010, 2009 and 2008 for more details.
In January 2010, the FASB issued ASU No. 2010-06, Improving Disclosures about Fair Value Measurements (“ASU 2010-06”). This update provides amendments to Subtopic 820-10 and requires new disclosures for 1) significant transfers in and out of Level 1 and Level 2 and the reasons for such transfers and 2) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, this update amends Subtopic 820-10 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements). The provisions in ASU 2010-06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010-06 did not impact the Company’s operating results, financial position or cash flows, but did impact the Company’s disclosures on fair value measurements. See Note 8-Derivative Instruments and Hedging Activities in the Notes to Consolidated Audited Financial Statements.
Item 7A.
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, 2010, a 10% decrease in the prices received for natural gas production would have had an approximate $3.3 million impact on our revenues, which would have been offset by approximately $1.8 million 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, 2010, we had $80.5 million of borrowings outstanding under our revolving credit facility. The rates at December 31, 2010 and 2009, excluding the effect of our interest rate swaps, were 3.30% and 3.03%, respectively. For the years ended December 31, 2010 and 2009, interest on the borrowings averaged 3.64% per annum and 3.12% per annum, respectively. All of the debt outstanding under our revolving credit facility accrues interest at floating or market rates. Fluctuations in market interest rates will cause our interest costs to fluctuate. Based upon the balance outstanding under our revolving credit facility for the year ended December 31, 2010, a 1% increase in market interest rates would have increased interest expense and negatively impacted our annual cash flows by approximately $0.8 million. $23.5 million of the outstanding balance was excluded from our market rate analysis due to lack of interest rate exposure based on the interest rate swaps we have in place.
Foreign Currency Exchange Rate Risk. We have operations in Canada and do not have operations in any other foreign countries. We do not hedge our foreign currency risk and are exposed to foreign currency exchange rate risk in the Canadian dollar. Our Canadian prospect is temporarily shut-in and, therefore, the impact on our Consolidated Financial Statements is not significant. We will continue to monitor the foreign currency exchange rate in Canada and may implement measures to protect against the foreign currency exchange rate risk in the future.
Item 8.
Item 8. Financial Statements and Supplementary Data
GEOMET, INC. AND SUBSIDIARIES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of GeoMet, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of GeoMet, Inc. and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the 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 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, such consolidated financial statements present fairly, in all material respects, the financial position of GeoMet, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, in 2009 the Company changed its method of accounting for natural gas reserves.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
April 6, 2011
GEOMET, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying Notes to Consolidated Audited Financial Statements.
GEOMET, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31,
See accompanying Notes to Consolidated Audited Financial Statements.
GEOMET, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME (LOSS)
See accompanying Notes to Consolidated Audited Financial Statements.
GEOMET, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying Notes to Consolidated Audited Financial Statements.
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS
Note 1-Organization and Our Business
GeoMet, Inc. (“GeoMet,” “Company,” “we,” or “our”) (formerly GeoMet Resources, Inc.) was incorporated under the laws of the state of Delaware on November 9, 2000. We are an independent natural gas producer primarily involved in the exploration, development and production of natural gas from coal seams (coal bed methane) and non-conventional shallow gas. Our principal operations and producing properties are located in Alabama, West Virginia, Virginia and Canada.
Note 2-Summary of Significant Accounting Policies
Principles of Consolidation-The accompanying Consolidated Audited Financial Statements are presented in conformity with accounting principles generally accepted in the United States of America (“GAAP”) and include our accounts and the accounts of our wholly-owned subsidiaries, GeoMet Operating Company, Inc., GeoMet Gathering Company LLC, GeoMet Gathering Virginia, Inc. (terminated June 28, 2010), and Hudson’s Hope Gas, Ltd. All inter-company accounts and transactions have been eliminated in consolidation.
Use of Estimates in the Preparation of Financial Statements-The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated audited financial statements and the reported amounts of revenues and expenses during the reporting period. Our most significant financial estimates are related to our proved gas reserves. Estimates of proved gas reserves are key components of our depletion rate for natural gas properties, our unevaluated properties and our full cost ceiling test limitation. In addition, other significant estimates include estimates used in computing taxes, stock-based compensation, asset retirement obligations, fair value of derivative contracts and accrued receivables and payables. Actual results could differ from these estimates.
Gas Properties-The method of accounting for 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 gas properties as prescribed by the United States Securities and Exchange Commission (“SEC”). For more information see Note 6-Gas Properties.
Unevaluated Properties-The costs directly associated with unevaluated properties and properties under development are not initially included in the amortization base and relate to unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination of proved reserves together with overhead and interest costs capitalized for these projects. Unevaluated leasehold costs are transferred to the amortization base once determination has been made or upon expiration of a lease. Geological and geophysical costs associated with a specific unevaluated property are transferred to the amortization base with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. All items included in our unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value. Any impairment to unevaluated properties is transferred to the amortization base.
Asset Retirement Liability-ASC 410-20-25 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 liability, 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 useful life of the related asset.
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Other Property and Equipment-The cost of other property and equipment is depreciated over the estimated useful lives of the related assets. The cost of leasehold improvements is depreciated over the lesser of the length of the related leases or the estimated useful lives of the assets. Depreciation is computed on the straight-line basis over the following estimated useful lives which range from three to seven years.
Cash and Cash Equivalents-For purposes of these statements, short-term investments, which have an original maturity of three months or less, are considered cash equivalents.
Inventory-Inventory consists primarily of materials and supplies used in the development and production of coal bed methane and is recorded at the lower of cost or market value using the specific identification costing method.
Notes Receivable Included in Stockholders’ Equity-We have loaned money to employees to purchase our common stock. Such amounts, including accrued interest, are recorded as Notes Receivable, and are included as a component of Stockholders’ Equity. The balances at December 31, 2010 and 2009 are solely attributable to employees.
Income Taxes-We record our income taxes using an asset and liability approach in accordance with the provisions of ASC 740, formerly SFAS No. 109, Accounting for Income Taxes. 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.
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 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. We typically do not have any significant producer gas imbalance positions because we own 100% working interest in the majority of our properties. 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
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
when our production delivered into the pipeline varies from the gas we nominated for sale. Pipeline imbalances are settled with cash approximately thirty days from date of production and are recorded as a reduction of revenue 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.
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 in the U.S. and Canada with only the U.S. currently having material revenue generating operating results.
Concentrations of Market Risk-Our future results will be affected by the market price of natural gas. The availability of a ready market for natural gas will depend on numerous factors beyond our control, including weather, production of natural gas, imports, marketing, competitive fuels, proximity of natural gas pipelines and other transportation facilities, any oversupply or undersupply of natural gas, the regulatory environment, and other regional and political events, none of which can be predicted with certainty.
Concentration of Credit Risk-Financial instruments, which subject us to concentrations of credit risk, consist primarily of cash, accounts receivable and derivative assets. We place our cash investments with highly qualified financial institutions. Risks with respect to receivables as of December 31, 2010 and 2009 arise substantially from the sales of natural gas and joint interest billings. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. Risks with respect to derivative assets as of December 31, 2010 arise from cash settlements due to us from our derivative counterparties. We have primarily one purchaser of our natural gas production. For the year ended December 31, 2010, 2009 and 2008, the aforementioned purchaser purchased 98%, 99% and 100%, respectively, of our net natural gas production. As of December 31, 2010 and 2009, the aforementioned purchaser represented 98% of our accounts receivable related to gas sales. At December 31, 2010 and 2009, we have recorded an allowance for doubtful accounts receivable of $60,848 related to other revenue and not a purchaser of our natural gas. We have not experienced any significant losses from uncollectible accounts. We do not believe the loss of our purchaser would materially affect our ability to sell the natural gas we produce as we believe other purchasers are available in our area of operations.
Operating Fees and Other-Operating fees and other for the years ended December 31, 2010, 2009 and 2008 include produced water disposal fees.
Capitalized General and Administrative Expenses-Under the full cost method of accounting, a portion of our general and administrative expenses that are directly attributable to our acquisition, exploration and development activities are capitalized as part of our natural gas properties. These capitalized costs include salaries, employee benefits, costs of consulting services and other costs directly associated with those activities. We capitalized general and administrative costs related to our acquisition, exploration and development activities, during the periods ended December 31, 2010, 2009, and 2008 of $971,467, $1,485,510, and $2,329,748, respectively.
Capitalized Interest Costs-We capitalize interest based on the cost of major development projects which are excluded from current depreciation, depletion and amortization calculations. For the years ended December 31, 2010 and 2009, we did not capitalize any interest. For the year ended December 31, 2008, we capitalized $304,342 of interest. See Unevaluated Properties above for additional information on the criteria for including costs in unevaluated properties.
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Derivative Instruments and Hedging Activities. Our hedging activities consist of derivative instruments entered into to hedge against changes in natural gas prices and changes in interest rates related to outstanding debt under our credit facility primarily through the use of fixed price swap agreements, basis swap agreements, three-way collars, and traditional collars. Consistent with our hedging policy, we entered into a series of derivative instruments to hedge a significant portion of our expected natural gas production through 2013. We also entered into an interest rate swap agreement to hedge interest rates associated with a portion of our variable rate debt through 2011. 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 consolidated audited financial statements in accordance with ASC 815, formerly SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Although not risk free, we believe this policy will reduce our exposure to natural gas price fluctuations and changes in interest rates 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.
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 or other comprehensive income (loss) for our interest rate swaps. The natural gas derivatives have not been designated as hedge transactions while the interest rate swaps qualify and have been designated as such in accordance with ASC 815-20-25.
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 hedge 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.
Mezzanine Equity /Embedded Derivative-Our Series A Convertible Redeemable 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. In addition, we evaluated the conversion feature and determined that because of certain anti-dilution provisions, the conversion feature was not indexed to our stock and as such, the holder’s conversion option was to be separated and recorded at fair value as a derivative liability. Subsequent changes in the fair value of the derivative liability were recorded as a component of other income and expense in the Consolidated Statements of Operations.
The fair value of the derivative liability attributable to the conversion option was determined using an American binomial lattice model, which utilized assumptions including 80% volatility, a 17% discount factor and an expected term of 6.4 years determined using a Monte Carlo simulation model. For the year ended December 31, 2010, the Company recorded approximately $2.1 million to Unrealized loss from change in fair value of derivative liability-Series A Convertible Redeemable Preferred Stock in the Consolidated Statements of Operations as a result of the change in the fair value of the derivative liability. On December 21, 2010, the Company amended the terms of the Preferred Stock to adjust the anti-dilution provision and further limit the Company’s ability to issue junior securities (including additional shares of common stock), at a price lower than the current conversion price, without the consent of holders of a majority of shares of Series A Preferred Stock. After the amendment, the conversion feature is indexed to our stock and as such, is no longer required to be accounted for as a derivative. On the effective date of the Amendment, the bifurcated derivative liability on the Company’s consolidated balance sheet related to the conversion feature was reclassified to paid-in capital on the Company’s consolidated statements of stockholders’ equity and comprehensive income (loss).
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Fair Value Measurement-Effective January 1, 2008, we adopted ASC 820-10-55, formerly SFAS No. 157, Fair Value Measurements, 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 related to the implementation of ASC 820-10-55 in Note 8-Derivative Instruments and Hedging Activities.
The fair value of cash and cash equivalents, current receivables and payables, approximate book value because of the short maturity of these accounts. The outstanding note receivable in Other Non-Current Assets and certain Other Debt carries a fixed interest rate. See Notes 5 and 10 for the fair values of the receivable and debt.
Foreign Currency Translation-For our wholly-owned Canadian subsidiary, Hudson’s Hope Gas, Ltd., whose functional currency is deemed to be other than the U.S. dollar, asset and liability accounts are translated at period end exchange rates and revenue and expenses are translated at average exchange rates prevailing during the period. Translation adjustments are included in the Accumulated Other Comprehensive Income (Loss). Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net (loss) income in the current period. Hudson’s Hope Gas, Ltd. is our only foreign subsidiary.
Stock-Based Compensation-We use the fair value recognition provisions of ASC 718, formerly SFAS No. 123(R), Share-Based Payment. 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 as of January 1, 2006, we will continue using the accounting principles originally applied to those awards before adoption. Therefore, we will not recognize any equity compensation cost on these prior awards in the future unless such awards are modified, repurchased or cancelled.
Note 3-Recent Accounting Pronouncements
In December 2008, the SEC issued Release No. 33-8995, Modernization of Oil and Gas Reporting (“ASC 2010-3”), which amended the oil and gas disclosures for oil and gas producers contained in Regulations S-K and S-X, and added a section to Regulation S-K (Subpart 1200) to codify the revised disclosure requirements in Securities Act Industry Guide 2, which was eliminated. The goal of Release No. 33-8995 is to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. Companies affected by Release No. 33-8995 are now required to price estimated proved oil and gas reserves using the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. SEC Release No. 33-8995 is effective beginning for financial statements for fiscal years ending on or after December 31, 2009. The Company adopted SEC Release No. 33-8995 effective December 31, 2009. The impact on the Company’s operating results, financial position and cash flows has been recorded in the consolidated audited financial statements and additional disclosures were added to the accompanying notes to the
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
consolidated audited financial statements for the Company’s supplemental oil and gas disclosure. See Supplementary Financial and Operating Information on Gas Exploration, Development and Producing Activities (Unaudited) for the years ended December 31, 2010, 2009 and 2008 for more details.
In January 2010, the Financial Accounting Standards Board (“FASB”) issued FASB Accounting Standards Update (“ASU”) No. 2010-03 Oil and Gas Estimation and Disclosures (“ASU 2010-03”). This update aligns the current oil and natural gas reserve estimation and disclosure requirements of the Extractive Industries Oil and Gas topic of the FASB Accounting Standards Codification (“ASC Topic 932”) with the changes required by the SEC final rule ASC 2010-3. As discussed above, ASU 2010-03 expands the disclosures required for equity method investments, revises the definition of oil- and natural gas-producing activities to include nontraditional resources in reserves unless not intended to be upgraded into synthetic oil or natural gas, amends the definition of proved oil and natural gas reserves to require 12-month average pricing in estimating reserves, amends and adds definitions in the Master Glossary that is used in estimating proved oil and natural gas quantities and provides guidance on geographic area with respect to disclosure of information about significant reserves. ASU 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009. The Company adopted ASU 2010-03 effective December 31, 2009. See Supplementary Financial and Operating Information on Gas Exploration, Development and Producing Activities (Unaudited) for the years ended December 31, 2010, 2009 and 2008 for more details.
In January 2010, the FASB issued ASU No. 2010-06, Improving Disclosures about Fair Value Measurements (“ASU 2010-06”). This update provides amendments to Subtopic 820-10 and requires new disclosures for 1) significant transfers in and out of Level 1 and Level 2 and the reasons for such transfers and 2) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, this update amends Subtopic 820-10 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements). The provisions in ASU 2010-06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010-06 did not impact the Company’s operating results, financial position or cash flows, but did impact the Company’s disclosures on fair value measurements. See Note 8-Derivative Instruments and Hedging Activities.
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Note 4-Net Income (Loss) Per Common Share
Income (Loss) Per Share of Common Stock-Earnings (loss) per share-basic is calculated by dividing net income (loss) available to common stockholders-basic by the weighted average number of shares of common stock outstanding during the period. Earnings (loss) per share-diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing net income (loss) available to common stockholders-diluted by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Earnings (loss) per share-diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares would have an anti-dilutive effect. A reconciliation of the numerator and denominator is as follows:
Diluted net income per share for the year ended December 31, 2010 excluded the effects of the Series A Convertible Redeemable Preferred Stock, as the net impact would have been anti-dilutive. The impact of the Series A Convertible Redeemable Preferred Stock would have included an addition to the numerator of the Accretion of Series A Convertible Redeemable Preferred Stock of $497,782 and dividends paid on Series A Convertible Redeemable Preferred Stock of $1,486,111 and an addition to the denominator of 9,188,620 in dilutive shares, as converted, which is the weighted average outstanding for the year based on 31,911,830 total shares outstanding, as converted.
Diluted net loss per share for the year ended December 31, 2009 excluded the effect of outstanding options to purchase 2,398,546 shares and 311,684 restricted shares because we reported a net loss which caused options to be anti-dilutive. Diluted net loss per share for the year ended December 31, 2008 excluded the effect of outstanding options to purchase 1,757,256 shares and 401,075 restricted shares because we reported a net loss which caused options to be anti-dilutive.
Note 5-Note Receivable
We have an unsecured note receivable of $209,728 and $242,074 as of December 31, 2010 and 2009, respectively, from a third party included in other non-current assets. The note requires payment on a
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
semi-monthly basis, including interest at 8.25%, of $2,168. The fair value of the receivable was $209,728 and $242,074 at December 31, 2010 and 2009, respectively. Scheduled maturities of the note receivable are detailed in the table below.
Note 6-Gas Properties
The method of accounting for 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 gas properties as prescribed by the United States Securities and Exchange Commission (“SEC”). Under this method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our gas properties are capitalized and segregated into United States of America (“U.S.”) and Canadian cost centers. The Canadian cost center was fully impaired in 2009 and remains impaired at December 31, 2010.
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. Depletion for the years ended December 31, 2010, 2009 and 2008 was $0.79, $1.51, and $1.35 per Mcf, respectively.
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 future reporting periods. No gains or losses are recognized upon the sale or disposition of 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 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 “ceiling limitation”). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. The ceiling test is performed separately for our U.S. and Canadian cost centers. 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 test is calculated using the unweighted arithmetic average of the natural gas price on the first day of each month within the twelve-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions, as allowed by the
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
guidelines of the SEC. In addition, subsequent to the adoption of Accounting Standards Codification (“ASC”) 410-20-25, formerly Financial Accounting Standard Board (“FASB”) Statement No. 143, Accounting for Asset Retirement Obligations, the future cash outflows associated with settling asset retirement obligations were not included in the computation of the discounted present value of future net revenues for the purposes of the ceiling test calculation.
For the year ended December 31, 2010, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $4.41 per Mcf, resulting in a natural gas price of $4.49 per Mcf when adjusted for regional price differentials. No impairments were recorded to gas properties for the year ended December 31, 2010.
For the year ended December 31, 2009, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $3.87 per Mcf, resulting in a natural gas price of $4.06 per Mcf when adjusted for regional price differentials. Impairments recorded to gas properties for the year ended December 31, 2009, were:
The natural gas price used in the valuation of natural gas reserves as of December 31, 2008 was $5.84 per Mcf ($5.71 Henry Hub spot market price for December 31, 2008, adjusted for regional price differentials). Impairments recorded to gas properties for the year ended December 31, 2008, were:
The following table provides a summary of the capitalized cost of our gas properties as of December 31, 2010 and 2009, by the year in which the costs were incurred.
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Note 7-Asset Retirement Liability
We record an asset retirement obligation (“ARO”) on the consolidated balance sheet and capitalize the asset retirement costs in gas properties in the period in which the retirement obligation is incurred. The amount of the ARO and the costs capitalized are equal to the estimated future costs to satisfy the obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date the abandonment obligation was incurred using an assumed cost of funds for GeoMet. Once the ARO is recorded, it is then accreted to its estimated future value using the same assumed cost of funds.
The following table describes the changes to our asset retirement liability for the years ending December 31, 2010 and 2009.
Note 8-Derivative Instruments and 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 from time to time 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 price movements. Our price risk management policy strictly prohibits the use of derivatives for speculative positions.
We enter 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. We generally limit the amount of these hedges during any period to no more than 50% to 70% of the then expected gas production for such future periods. 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. Three-way costless collars are similar to regular costless collars except that, in order to increase the ceiling price, we agree to limit the amount of the floor price protection (through a sold floor) to a predetermined amount, generally between $2.00 and $3.00 per MMBtu below the bought floor. 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.
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Commodity Price Risk and Related Hedging Activities
At December 31, 2010, we had the following natural gas collar positions:
At December 31, 2009, we had the following natural gas collar positions:
At December 31, 2010, we had the following natural gas swap positions:
At December 31, 2009, we had the following natural gas swap positions:
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Our production is sold at an “all-in” price which includes the market price for natural gas plus a “basis differential”. In January 2011, we agreed to sell gross volumes of 16,000 MMBtu/day of natural gas from our Pond Creek field for the period February 2011 through March 2012 through a forward physical sale contract with our existing purchaser at a price equal to the last day settlement price for the NYMEX contract for the month of sale plus a basis differential of $0.15, $0.115, and $0.13 for the periods February 2011 through March 2011, April 2011 through October 2011, and November 2011 through March 2012, respectively. Gross sales from the Pond Creek field averaged approximately 17,800 MMBtu/day for the year ended December 31, 2010. As such, the overall delivery agreement represents approximately 90% of the 2010 average gross daily sales. Additionally, we fixed the NYMEX settle on a portion of the aforementioned forward sale as follows:
The remaining volumes giving effect for the fixed amounts denoted above are as follows:
The aforementioned forward physical sale contract is defined as a derivative contract under ASC 815. However, it qualifies for the normal purchase and sale exemption and will not be marked-to-market on the Consolidated Balance Sheets.
Interest Rate Risks and Related Hedging Activities
When we enter into an interest rate swap, we may designate the derivative as a cash flow hedge, at which time we prepare the documentation required under ASC 815-20-25. Hedges of our interest rate are designated as cash flow hedges based on whether the interest on the underlying debt is converted to a fixed interest rate. Changes in derivative fair values that are designated as cash flow hedges are deferred as other comprehensive income or loss to the extent that they are effective and then recognized in earnings when the hedged transactions occur.
We use fixed rate swaps to limit our exposure to fluctuations in interest rates with the objective of realizing a fixed cash flow stream from these activities. At December 31, 2010, we had the following interest rate swaps:
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
At December 31, 2009, we had the following interest rate swaps:
(1) The floating rate paid by the counterparty is the British Bankers’ Association LIBOR rate.
On September 14, 2010, we de-designated the remaining two interest rate swaps which we had previously designated as cash flow hedges under ASC 815-20-25. The de-designation resulted from entering into the Fourth Amended and Restated Credit Agreement which replaced our Third Amended and Restated Credit Agreement. In the new agreement, the notional and interest rates no longer match, and therefore, these two interest rate swaps are no longer effective hedges under ASC 815-20-25. Subsequently, we accounted for the remaining interest rate swaps on a mark-to-market basis which gave rise to both realized and unrealized gains and losses recorded in Interest expense (net of amounts capitalized) in the Consolidated Statements of Operations. Amounts in accumulated other comprehensive income have been frozen and are reclassified into earnings as the forecasted transactions impact earnings.
For the years ended December 31, 2010, 2009 and 2008, we recognized no ineffective portion of our cash flow hedges. We have reviewed the financial strength of our hedge counterparties and believe our credit risk to be minimal. Our hedge counterparties are participants in our revolving credit facility agreement and the collateral for the outstanding borrowings under our revolving credit facility agreement is used as collateral for our hedges. We do not have rights to collateral from our counterparties, nor do we have rights of offset against borrowings under our revolving credit facility agreement.
The application of ASC 820-10-55, formerly SFAS No. 157, Fair Value Measurements, currently applies to our derivative instruments. Under the provisions of ASC 820-10-55, we estimate the fair value of our natural gas hedges and interest rate swaps using the income approach. The income approach uses valuation techniques that convert future cash flows to a single discounted value. ASC 820-10-55 clarifies that a fair value measurement for an asset or liability reflects its nonperformance risk, the risk that the obligation will not be fulfilled. Because nonperformance risk includes our counterparties’ and our credit risk, we have considered the effect of our credit risk on the fair value of the liabilities stated below. This consideration involved discounting our counterparties’ and our liabilities based on the difference between the S&P credit rating of a comparable company to ours and the 13-week Treasury bill rate, both as of the reporting date. The following is a description of the valuation methodologies used for our derivative instruments measured at fair value:
•
Natural Gas Hedges-In order to estimate the fair value of our natural gas hedge positions, a forward natural gas price curve and volatility estimates were compiled from sources that include NYMEX settlements and observed trading activity in the Over-the-Counter (OTC) markets. Pricing estimates for the theoretical market value of hedge positions were developed using analytical models accepted and employed by a broad cross-section of industry participants. To extrapolate future cash flows, discount factors incorporating our counterparties’ and our credit standing are used to discount future cash flows.
•
Interest Rate Swaps-In order to estimate the fair value of our interest rate swaps, we use an interest yield curve based on Money Market rates and Interest Rate swaps, extrapolate a forecast of future
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available Money Market rates and Interest Rate swap market data. To extrapolate future cash flows, discount factors incorporating our counterparties’ and our credit standing are used to discount future cash flows.
•
Series A Convertible Redeemable Preferred Stock-Upon issuance, the fair value of an embedded derivative liability attributable to the conversion option of the Series A Convertible Redeemable Preferred Stock was bifurcated on the Consolidated Balance Sheet. The fair value of the liability was determined using an American binomial lattice model, which utilized assumptions including 80% volatility and a 17% discount factor. Based on an amendment to the terms of the Preferred Stock made on December 21, 2010, the liability was extinguished and reclassified to Paid-in capital on the Consolidated Balance Sheet at December 31, 2010. Changes in the fair value of the derivative liability were recorded as Unrealized loss from change in fair value of derivative liability-Series A Convertible Redeemable Preferred Stock in the Consolidated Statements of Operations for the year ended December 31, 2010.
We did not have any transfers of assets and liabilities between Level 1 and Level 2 of the fair value measurement hierarchy during the year ended December 31, 2010. Based on the use of observable market inputs, we have designated these types of instruments designated below as Level 2 for ASC 820-10-55 reporting purposes. The fair value of our Level 2 derivative instruments were as follows:
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
The following (gains) losses on our hedging instruments included in the consolidated statements of operations and other comprehensive (loss) income (“OCI”) are as follows:
The Effect of Derivative Instruments on the Consolidated Statements of Operations and
Other Comprehensive Income for the Years Ended December 31, 2010 and 2009
Accumulated comprehensive loss of $1,324,154 as of December 31, 2010 consists of $1,313,292 in foreign currency translation adjustment and a $10,862 loss (net of income tax benefit of $6,714) on interest rate swaps, net of income tax benefit. Accumulated comprehensive loss of $10,862 as of December 31, 2010 is expected to be realized as interest expense in the Consolidated Statement of Operations in the year ended December 31, 2011. Accumulated comprehensive loss of $1,768,521 as of December 31, 2009 consists of $1,321,173 in foreign currency translation adjustments and a $447,348 loss (net of income tax benefit of $276,517) on interest rate swaps, net of income tax benefit. Accumulated comprehensive loss of $2,399,992 as of December 31, 2008 consists of $1,721,505 in foreign currency translation adjustments and a $678,487 loss (net of income tax benefit of $410,906) on interest rate swaps, net of income tax benefit.
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Note 9-Terminated Transaction Costs
Terminated transaction costs consist of payments made related to a terminated financing transaction between the Company, NGP Capital Resources Company (“NGPC”) and North Shore Energy, LLC (“North Shore”), an affiliate of Yorktown Energy Partners IV, L.P. (“Yorktown”) (Yorktown is a related party to the Company) and expenses related to a terminated sale of certain gas properties. The following is a detail of terminated transaction costs and related party amounts for the year ended December 31, 2010:
Note 10-Long-Term Debt
On September 14, 2010, our Fourth Amended and Restated Credit Agreement (the “Credit Agreement”) with a group of five banks became effective. The Credit Agreement replaced our Third Amended and Restated Credit Agreement and provides for revolving credit borrowings of up to $180 million with an initial borrowing base of $90 million. The borrowing base will be determined as of each June and December with the next determination scheduled to be completed by June 2011. All outstanding borrowings under the Credit Agreement become due and payable on September 14, 2013. The Credit Agreement provides for interest to accrue at a rate calculated, at the Company’s option, at the Adjusted Base Rate plus a margin of 1.75% to 2.25% or the London Interbank Offered Rate (the “LIBOR Rate”) rate plus a margin of 2.75% to 3.25%. 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%). In all cases the applicable margin is dependent on the percentage of borrowing base usage. Under the Credit Agreement we are subject to certain financial covenants requiring maintenance of (i) a minimum Current Ratio, (ii) a maximum Debt Ratio and, (iii) depending on our Debt Ratio, either (a) a minimum Interest Coverage Ratio or (b) a minimum Fixed Charge Ratio. The Current Ratio of consolidated current assets (defined to include amounts available under our borrowing base) to consolidated current liabilities (defined to exclude up to $1.5 million in accrued and unpaid preferred dividends) is not permitted to be less than 1.0 to 1.0 as of the end of any fiscal quarter. The Debt Ratio (defined as funded debt at the end of each fiscal quarter to trailing four quarter consolidated EBITDA) at the end of each fiscal quarter cannot exceed 4.5 to 1.0 through the quarter ending June 30, 2011 and 4.0 to 1.0 thereafter. If our Debt Ratio at the end of each fiscal quarter is above 3.5 to 1.0, then the Fixed Charge Ratio (defined as consolidated EBITDA less capital expenditures to consolidated net cash interest expense for the four preceding quarters) is applicable and cannot be less than 1.25 to 1.0. If our Debt Ratio at the end of each fiscal quarter is 3.5 to 1.0 or less, the Interest Coverage Ratio (defined as consolidated EBITDA to consolidated net cash interest expense plus letter of credit fees accruing during the preceding four quarters) is applicable and cannot be less than 2.75. Consolidated EBITDA is defined as earnings (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization and also excludes non-recurring charges and other non-cash charges deducted in determining net income (loss), which would include unrealized gains and losses from a change in the market value of open derivative contracts. We are also subject to covenants restricting or prohibiting cash dividends and other restricted payments, transactions with affiliates, incurrence of debt, consolidations and mergers, the level of operating leases, assets sales, investments in other entities, and liens on properties. Cash dividends on our
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
preferred stock are permitted if, following any such cash payment our availability is equal to or greater than 15% of the then current borrowing base and our Debt Ratio is less than 3.5 to 1.0. There are no restrictions associated with the payment of PIK dividends on our preferred stock.
As of December 31, 2010, we had $80.5 million of borrowings outstanding under our revolving credit facility, resulting in a borrowing availability of $9.5 million under our $90.0 million borrowing base, subject to compliance with covenants. For the year ended December 31, 2010 we borrowed $28.75 million and made payments of $67.75 million under the revolving credit facility. The rate at December 31, 2010, excluding the effect of our interest rate swaps, was 3.30% per annum. For the year ended December 31, 2010, interest on the borrowings averaged 3.64% per annum.
As of December 31, 2009, we had $119.5 million of borrowings outstanding under our revolving credit facility, resulting in a borrowing availability of $15.5 million under our $135.0 million borrowing base. For the year ended December 31, 2009 we borrowed $39.4 million and made payments of $36.4 million under the revolving credit facility. The rate at December 31, 2009, excluding the effect of our interest rate swaps, was 3.03% per annum. For the year ended December 31, 2009, interest on the borrowings averaged 3.12%.
The following is a summary of our long-term debt at December 31, 2010 and 2009:
The fair value of long-term debt at December 31, 2010 and 2009 was estimated to be approximately $68.4 million and $115.8 million, respectively. ASC 820-10-55 clarifies that a fair value measurement for an asset or liability reflects its nonperformance risk, the risk that the obligation will not be fulfilled. Because nonperformance risk includes our credit risk, we have considered the effect of our credit risk on the fair value of the long-term debt. This consideration involved discounting our long-term debt based on the difference between the market weighted average cost of equity capital plus a premium over the capital asset pricing model and the stated interest rates of the debt instruments included our long-term debt.
In connection with the Fourth Amended and Restated Credit Agreement that became effective September 14, 2010, we incurred $1.4 million in deferred financing costs. The deferred financing costs will be amortized over the term of the credit agreement. In addition, we expensed $0.1 million related to the Third Amended and Restated Credit Agreement which was replaced at that time. In connection with the Third Amended and Restated Credit Agreement, we incurred $0.3 million in deferred financing costs.
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
The following were maturities of long-term debt for each of the next five years at December 31, 2010:
Note 11-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.
For tax reporting purposes, we have federal and state NOL’s of approximately $113.6 million and $123.0 million, respectively, at December 31, 2010 that are available to reduce future taxable income. For tax reporting purposes, we had federal and state NOL’s of approximately $97.7 million and $106.4 million, respectively, at December 31, 2009 that were available to reduce future taxable income.
ASC 740 requires the Company to recognize income tax benefits for loss carry forwards that have not previously been recorded. The tax benefits recognized must be reduced by a valuation allowance when it is more likely than not that the deferred tax asset will not be realized. The Company has a net deferred tax asset of $46.0 million and $51.6 million as of December 31, 2010 and 2009, respectively, which includes recorded valuation allowances of $3.1 million and $2.7 million, respectively. Our valuation allowances primarily relate to our Canadian operations where we do not believe it is more likely than not that we will recover our net deferred tax asset prior to expiration and have recorded a full valuation allowance as we currently have no proved reserves in Canada. In addition, we have recorded a valuation allowance for certain immaterial state net operating losses where the Company has ceased operations.
Our first material net operating loss (“NOL”) carryforward expires in 2022 and the last one expires in 2030. We also consider the lengthy carryforward period in the overall evaluation of our ability to realize our NOLs as it substantially increases the likelihood of utilization.
In determining the carrying value of a deferred tax asset, ASC 740 provides for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. In order to assess the realization of our net deferred tax asset as of December 31, 2010 and 2009, the Company considered all available negative and positive evidence. While the Company has incurred a cumulative loss over the three year period ended December 31, 2010, after evaluating all available evidence including historical operating results, historical pricing, current operating income, consideration of the full cost ceiling test impairments in 2009 and 2008 that resulted in the cumulative losses, our reserves level as estimated and appraised by an independent third party engineer, future pricing as indicated on the New York Mercantile Exchange, and the length of the carryforward period available, the Company concluded that it is more likely than not the deferred tax asset, net of the $3.1 valuation allowance related to our Canadian operations and state NOLs, will be realized. The Company will
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
continue to assess the need for additional valuation allowances in the future. If future results are less than projected using either our historical results or our forecast based on the reserve report and future market pricing, then additional valuation allowances may be required to reduce the deferred tax assets which could have a material impact on the Company’s results of operations in the period in which it is recorded.
Deferred Tax Assets and Liabilities
An analysis of our deferred tax assets and liabilities as of December 31, 2010 and 2009:
Effective Tax Rate
Our effective tax rate differs from the federal statutory rate primarily due to the recording of valuation allowances primarily related to our Canadian operations and other nondeductible items as detailed below. The nondeductible transaction costs below relate to a terminated transaction described in Note 9-Terminated Transaction Costs. Income tax expense for the year ended December 31, 2010 was different than the amount computed using the statutory rate as follows:
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Income tax expense for the year ended December 31, 2009 was different than the amount computed using the statutory rate as follows:
Income tax expense for the for the year ended December 31, 2008 was different than the amount computed using the statutory rate as follows:
The following components of the income tax expense for the years ended December 31, 2010, 2009 and 2008 are as follows:
Uncertain Tax Positions
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 amount of unrecognized tax benefits of $272,600 has not changed in the three year period ended December 31, 2010. It is expected that the amount of unrecognized tax benefits may change in the next twelve months; however we do not expect the change to have a significant impact on our results of operations or the financial position.
We file a consolidated federal income tax return in the U.S. and various combined and separate filings in Canada and several state and local jurisdictions. With limited exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2002.
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Our continuing practice is to recognize estimated interest related to potential underpayment on any unrecognized tax benefits as a component of interest expense in the consolidated statement of operations. Penalties, if incurred, would be recognized as a component of penalty expense. We did not have any accrued interest or penalties associated with any unrecognized tax benefits at December 31, 2010 and 2009, nor was any interest expense recognized during the years ended December 31, 2010, 2009 and 2008. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to December 31, 2011.
Note 12-Common Stock
At December 31, 2010 and 2009, there were 39,758,484 and 39,460,060 shares, respectively, of common stock outstanding, both including 10,432 shares of treasury stock held by the Company. Also included in common stock outstanding at December 31, 2010 and 2009 were 292,512 and 311,684 shares of restricted stock, respectively.
For the year ended December 31, 2010, 75,190 shares of common stock were issued upon the exercise of stock options granted under our 2006 Long-Term Incentive Plan. No common stock was issued upon the exercise of stock options granted under our 2005 Stock Option Plan. On September 20, 2010, we issued 157,622 shares of common stock to our independent directors, representing 50% of their 2010 annual retainer. Additionally, on September 20, 2010, we issued 132,492 performance-based shares of restricted stock to the executives of the Company. For the year ended December 31, 2010, 66,194 shares of restricted stock were forfeited. On March 24, 2010, 300 shares of common stock were purchased by us from a non-executive employee for the payment of $289 in withholding taxes due on vested shares of restricted stock issued under our 2006 Long-Term Incentive Plan. On June 15, 2010, 386 shares of common stock were purchased by us from a non-executive employee for the payment of $494 in withholding taxes due on vested shares of restricted stock issued under our 2006 Long-Term Incentive Plan. The shares were not retained as treasury stock as they were immediately cancelled.
For the year ended December 31, 2009, no common stock was issued upon the exercise of stock options granted under our 2005 Stock Option Plan and our 2006 Long-Term Incentive Plan. On March 23, 2009, we issued 166,668 shares of common stock to our independent directors representing 50% of their 2009 retainer. For the year ended December 31, 2009, 11,354 shares of restricted stock were forfeited. On June 15, 2009, 403 shares of common stock were purchased by us from a non-executive employee for the payment of $613 in withholding taxes due on vested shares of restricted stock issued under our 2006 Long-Term Incentive Plan. The shares were not retained as treasury stock as they were immediately cancelled.
For the year ended December 31, 2008, a total of 68,605 shares of common stock were issued upon the exercise of stock options granted under our 2005 Stock Option Plan and no stock options were granted. In March 2008, we issued 253,806 shares of restricted stock to key employees, including four executive officers and two other officers, of the Company and 18,720 shares of common stock to our independent directors, representing 50% of their annual retainer. In September 2008, we issued 46,694 shares of restricted stock to key employees of the Company. The shares of common stock for our independent directors and the restricted stock were issued pursuant to our 2006 Long-Term Incentive Plan. For the year ended December 31, 2008, 45,032 shares of restricted stock were forfeited.
Note 13-Series A Convertible Redeemable Preferred Stock
On September 14, 2010, the Company issued and sold 4,000,000 shares of Series A Convertible Redeemable Preferred Stock (“Preferred Stock”), par value $0.001 per share, at a price of $10.00 per share. After
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
paying transaction fees and expenses in the amount of $2.8 million, the Company used the net proceeds of approximately $37.2 million to reduce outstanding bank debt. The Preferred Stock ranks senior to our common stock as to payment of dividends and distribution upon liquidation.
Dividends accrue quarterly on the Preferred Stock, including any Preferred Stock issued as paid-in-kind dividends (“PIK dividends”), which in our sole discretion, may be paid in any combination of cash, or, until the fifth anniversary of the closing of the rights offering, in PIK dividends. The applicable annual rate for dividends paid in cash is 8.0% for the first three years and 9.6% thereafter. The applicable annual rate for PIK dividends is 12.5%. All dividends are cumulative and all unpaid dividends compound on a quarterly basis at a 12.5% annual rate. At December 31, 2010, an additional 3,253,294 shares of our Preferred Stock are reserved exclusively for the payment of PIK dividends.
The Preferred Stock is immediately convertible into common stock, at the sole option of the holder, at an initial conversion price of $1.30 per common share (as it may be adjusted from time to time, the “Conversion Price”). The Preferred Stock converts into a number of shares of common stock determined by dividing (i) the sum of (A) $10.00 plus (B) accrued but unpaid dividends by (ii) the Conversion Price. At the current Conversion Price, up to an additional 31,911,830 shares of our common stock would be outstanding immediately after conversion of our Preferred Stock. The Conversion Price and resulting number of shares of common stock issued upon conversion of Preferred Stock is adjusted to reflect stock splits and similar events and is entitled to anti-dilution adjustments for any dividends paid on common stock in cash or in common stock, the issuance of additional equity securities at a price less than the Conversion Price (excluding shares, rights and options subject to certain employee benefit arrangements), and the occurrence of certain material corporate transactions at a per share valuation less than the Conversion Price.
At any time beginning eight years from the date of issuance, the Preferred Stock is redeemable, in whole or in part, at the sole option of the holder. The purchase price per share, payable in cash, will be equal to the sum of the original purchase price and any accrued and unpaid dividends.
We have the option, beginning three years from the date of issuance, to convert the Preferred Stock into our common stock at the then current Conversion Price, subject to certain volume and other limitations. In order for us to exercise this option, the daily volume-weighted average trading price of our common stock must be greater than 225% of the then current Conversion Price for twenty (20) out of the previous thirty (30) trading days.
The holders of the Preferred Stock are entitled to vote on all matters on which the holders of our common stock are entitled to vote. The holders of the Preferred Stock generally vote together with the holders of the common stock as a single class, with the Preferred Stock holders entitled to the number of votes such holders would have on an as-converted basis. Certain actions also require a separate vote of the Preferred Stock.
Upon the occurrence of a liquidation, dissolution or winding up of the Company resulting in a payment or distribution of assets to the holders of any of our capital stock (each such event, a “Liquidation Event”), the holders of the Preferred Stock (including PIK dividends) are entitled to receive, prior and in preference to any payment, or segregation for payment, of any consideration to any holder of any junior security of the Company, an amount in cash equal to the greater of (i) $10.00 per share, plus any accrued but unpaid dividends (in each case adjusted for any stock dividends, splits, combinations or similar events), or (ii) an amount equal to the amount such holders of the Preferred Stock would have received upon the Liquidation Event if they had converted their shares of Preferred Stock into shares of our common stock.
If not converted, the Preferred Stock (including any PIK dividends) is redeemable by us on or at any time after a Liquidation Event. In the absence of a Liquidation Event, if not converted, a holder of Preferred Stock
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
(including any PIK dividends) may cause us to redeem the Preferred Stock held by such holder, in whole or in part, on or after September 14, 2018, upon 30 days prior written notice to us. Upon any redemption of Preferred Stock by us, as of the effective date of the redemption, we will pay to each holder of Preferred Stock, $10.00 per share of Preferred Stock (including any PIK dividends) held plus any accrued but unpaid dividends (in each case adjusted for any stock dividends, splits, combinations or similar events).
During the year ended December 31, 2010, the Company declared and issued PIK dividends of 148,538 shares to the holders of Preferred Stock.
The 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. The Preferred Stock balance in mezzanine equity will be accreted to its redemption value over the eight year redemption period. In addition, we evaluated the conversion feature at September 14, 2010 and determined that its terms required the holder’s conversion option to be separated and recorded at fair value as a derivative liability on the Consolidated Balance Sheet. Subsequent changes in the fair value of the derivative liability were recorded as a component of other income and expense in the Consolidated Statements of Operations.
The fair value of the derivative liability attributable to the conversion option was determined using an American binomial lattice model, which utilized assumptions including 80% volatility, a 17% discount factor and an expected term of 6.4 years determined using a Monte Carlo simulation model, and resulted in a fair value of approximately $18.4 million on the date of issuance. The remaining net proceeds of $20.4 million were allocated to Series A Convertible Redeemable Preferred Stock in the Consolidated Balance Sheets. For the year ended December 31, 2010, the Company recorded approximately $2.1 million to Unrealized loss from change in fair value of derivative liability-Series A Convertible Redeemable Preferred Stock in the Consolidated Statements of Operations as a result of the change in the fair value of the derivative liability.
On December 21, 2010, the Company amended the terms of the Preferred Stock to adjust the anti-dilution provision and further limit the Company’s ability to issue junior securities (including additional shares of common stock), at a price lower than the current conversion price, without the consent of holders of a majority of shares of Series A Preferred Stock.
The Preferred Stock initially contained an anti-dilution provision that was triggered when the Company issued certain additional common stock or securities convertible into common stock for consideration per share less than the conversion price of the Preferred Stock. The anti-dilution provision was amended during 2010 so that, in the event of such issuance, the conversion price of the Preferred Stock will be reduced to a price determined by multiplying the then-current conversion price by a fraction (a) the numerator of which will be the sum of (i) the number of shares of common stock outstanding, on a fully diluted basis, before the additional issuance plus (ii) the number of shares of common stock which the aggregate consideration received by the Company for the additional issuance would purchase at the conversion price then in effect, and (b) the denominator of which will be the sum of (x) the number of shares of common stock outstanding before the additional issuance plus (y) the number of such additional shares of common stock that were actually issued.
In addition, the terms of the Preferred Stock was amended to prohibit the Company from issuing 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 Series A Preferred Stock without the prior vote or consent of holders of a majority of the outstanding shares of Series A Preferred Stock, for so long as at least 750,000 shares of Series A Preferred Stock remain outstanding.
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
We amended the terms of the Preferred Stock because we believed that the valuation, accounting and disclosure obligations associated with the embedded derivative were burdensome and that such accounting treatment did not clearly represent the overall financial condition and results of operations of the Company. Determining the periodic change in the fair value of the derivative liability required a costly valuation each quarter and produced significant volatility in the Company’s consolidated balance sheet and consolidated statement of operations. In addition, the valuation required Level 3 inputs and assumptions, under ASC 820-10-55, for reporting purposes, and was considered a critical accounting area which includes a high degree of judgment and uncertainty.
On the effective date of the Amendment, December 21, 2010, the bifurcated derivative liability on the Company’s consolidated balance sheet related to the conversion feature was reclassified to paid-in capital on the Company’s consolidated statements of stockholders’ equity and comprehensive income (loss). In addition, we will no longer experience the potential volatility on the consolidated balance sheets and consolidated statements of operations from unrealized gains or losses resulting from future fair value fluctuations of the extinguished derivative liability. As a result, we expect our consolidated financial statements to be more consistent with the underlying operations of the Company.
The following table details the activity related to the issuance and accretion of the Series A Convertible Redeemable Preferred Stock and the related derivative liability for the year ended December 31, 2010:
(1) Issuance costs of $2,832,472 were incurred as part of the issuance of the Series A Convertible Redeemable Preferred Stock. As the Series A Convertible Redeemable Preferred Stock was bifurcated on the Consolidated Balance Sheet as disclosed in the table above, $1,531,056 of the issuance costs were allocated to Mezzanine Equity-Series A Convertible Redeemable Preferred Stock. The remaining $1,301,416 of
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
issuance costs were allocated to Other current assets and Other noncurrent assets to be amortized over the term of the Series A Convertible Redeemable Preferred Stock and, as a result of the amendment to the Preferred Stock agreement on December 21, 2010, $1,261,343($1,301,416 of original issuance costs, less $40,073 amortized in 2010) were reclassified to equity.
Note 14-Share-Based Awards
As of December 31, 2010, we have two stock-based award plans authorized, which include our 2005 Stock Option Plan and our 2006 Long-Term Incentive Plan. However, we will not grant any additional awards under our 2005 Stock Option Plan now that we have adopted our 2006 Long-Term Incentive Plan. The 2005 Stock Option Plan was terminated on March 11, 2011 as no options granted under the plan remained outstanding at that time.
Our 2006 Long-Term Incentive Plan authorized the granting of incentive stock options, non-qualified stock options, stock appreciation rights, stock awards, restricted stock, restricted stock units and performance awards. A maximum of 4,000,000 shares is available for grant under this plan. The 2006 Long-Term Incentive Plan is available to our employees and independent directors and is designed to attract and retain employees and independent directors, to further align the interests of our employees and independent directors with the interests of our stockholders, and to closely link compensation with our performance. The exercise price of stock options granted under this plan may not be less than the fair market value of the common stock on the date of grant. The options generally have a term of seven years and vest evenly over three years, except performance based awards, granted to our named executive officers, and options issued to directors. Performance based awards granted under the 2006 Long-Term Incentive Plan vest once the performance criteria have been met. Options granted to our directors vest immediately.
During the year ended December 31, 2010, we recorded a compensation expense accrual of $510,840 of which $43,292 was allocated to lease operating expenses, $364,295 was allocated to general and administrative expenses, and $103,253 was capitalized to gas properties.
During the year ended December 31, 2009, we recorded a compensation expense accrual of $978,634 of which $54,008 was allocated to lease operating expenses, $738,568 was allocated to general and administrative expenses, and $186,058 was capitalized to gas properties.
During the year ended December 31, 2008, we recorded a compensation expense accrual of $941,697 of which $53,737 was allocated to lease operating expenses, $512,680 was allocated to general and administrative expenses, and $375,280 was capitalized to gas properties.
At December 31, 2010, the future compensation cost of all the outstanding awards is $584,351 which will be amortized over the vesting period of such stock options and restricted stock. The weighted average remaining useful life of the future compensation cost is 1.08 years.
For the year ended December 31, 2010, the significant assumptions used in determining the compensation costs included an expected volatility from 79.3% to 83.7%, risk-free interest rate of 1.47%, an expected term from 4.39 to 4.83 years, forfeiture rates from 5% to 15%, and no expected dividends. For the year ended December 31, 2009, the significant assumptions used in determining the compensation costs included an expected volatility of 56.10%, risk-free interest rate of 1.25%, an expected term of 4.5 years, forfeiture rates from 5% to 15%, and no expected dividends. For the year ended December 31, 2008, no stock options were granted.
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Incentive Stock Options
The table below summarizes incentive stock option activity for the three years ended December 31, 2010:
During the years ended December 31, 2010 and 2009, incentive stock options were granted with a weighted average grant-date fair value of $0.55 and $0.33 per option, respectively. The total intrinsic value of incentive stock options exercised during the years ended December 31, 2010 and 2008 was $29,414 and $553,567, respectively.
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Non-Qualified Stock Options
The table below summarizes non-qualified stock option activity for the three years ended December 31, 2010:
During the year ended December 31, 2009, non-qualified stock options were granted with a weighted average grant-date fair value of $0.33 per option.
Restricted Stock Awards
The table below summarizes non-vested restricted stock awards activity for the three years ended December 31, 2010:
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Option Exchange
The Company issued a Tender Offer on Schedule TO on December 7, 2010 offering eligible employees the opportunity to exchange certain outstanding stock options for a number of new restricted shares of GeoMet common stock (“Restricted Stock”), to be granted under the GeoMet, Inc. 2006 Long-Term Incentive Plan (the “2006 Plan”). Options eligible for exchange, or eligible options, were those options, whether vested or unvested, that met all of the following requirements:
•
the options had a per share exercise price greater than $5.00;
•
the options were granted under one of our existing equity incentive plans;
•
the options were outstanding and unexercised as of January 5, 2010;
•
the options were not granted within the twelve-month period immediately preceding the commencement of this offer, December 7, 2010; and
•
the options did not have a remaining term of less than 12 months immediately following January 5, 2010.
On January 5, 2011, upon completion of the Tender Offer, 98,416 shares of restricted stock were granted to those eligible employees as follows:
Note 15-Profit Sharing Plan
Substantially all of the employees are covered by our profit sharing plan under Section 401(k) of the Internal Revenue Code. Eligible employees may make contributions to the plan by electing to defer some of their compensation. We are required to match 100 percent of the first three percent of their annual compensation contributed and 50 percent of the following two percent of their annual compensation contributed. Our matching contribution vests evenly over three years. Once a participant is fully vested all future matching contributions vest immediately. Our contributions to the Plan for the years ended December 31, 2010, 2009 and 2008 were $198,131, $216,842, and $264,305, respectively. Additionally, during the year ended December 31, 2010, we elected in to be Safe Harbor for the year ended December 31, 2011. A Safe Harbor 401(k) plan generally satisfies the non-discrimination rules for elective deferrals and employer matching contributions. For a 401(k) plan to be considered a Safe Harbor plan, employers must satisfy certain contribution, vesting, and notice requirements. Under Safe Harbor, the matching contributions will vest immediately.
Note 16-Commitments and Contingencies
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 cannot be predicted with certainty, management does not believe that the adverse effect on our financial condition, results of operations or cash flows, if any, will be material.
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
EQT Production Company Claim
In March 2011, we received a letter from EQT Production Company (“EQT”) stating that our fracturing operations in 2010 had damaged a well owned by EQT, and demanding the payment of the value of the well and other amounts totaling approximately $430,000. In April 2011, EQT revised their demand for payment to approximately $464,000. We are reviewing the claim to determine if we are liable for the damages alleged to have been sustained by EQT. We believe that if we are responsible for the damages, substantially all of the loss will be covered by our insurance. A majority of our proved undeveloped locations in the Pond Creek field are owned by us through a farmout agreement with EQT that provides that if we default under the agreement, our future development rights under the farmout agreement terminate. The failure to pay the amount of any damages to EQT for which we are liable may be a default as defined in the farmout agreement. We do not believe that the payment of any damages to EQT for which we may be liable will have a material impact on our results of operations, financial position nor cash flows.
Environmental and Regulatory
As of December 31, 2010, 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.
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, 2010 under non-cancelable operating leases having remaining terms in excess of one year are as follows:
Total rental expenses under operating leases were approximately $1,528,739, $1,857,026, and $2,005,994 for the years ended December 31, 2010, 2009 and 2008, respectively.
Transportation Contracts-As of December 31, 2010, 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, and (3) 10,000 MMBtu’s continuing until April 1, 2017. We have a right to extend each of these contracts, in five-year increments, at the maximum tariff rate. As of December 31, 2010, the maximum commitment remaining under the transportation contracts is approximately $12.3 million.
GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Note 17-Additional Financial Statement Information
Certain balance sheet amounts are comprised of the following:
SUPPLEMENTARY FINANCIAL AND OPERATING INFORMATION ON GAS
EXPLORATION, DEVELOPMENT AND PRODUCING ACTIVITIES (UNAUDITED)
This supplemental schedule provides unaudited information pursuant to ASC 932, formerly SFAS No. 69, Disclosures About Oil and Gas Producing Activities-an amendment of FASB Statements No. 19, 25, 33, and 39) and certain other information.
Capitalized Costs-Capitalized costs and accumulated depletion and impairment of gas properties relating to our gas producing activities, all of which are conducted within the continental U.S. and Canada at December 31, 2010, 2009, and 2008 are summarized below.
Capitalized Costs Incurred
We capitalize certain payroll and other internal costs directly attributable to acquisition, exploration and development activities as part of our investment in natural gas properties over the periods benefited by these activities. During the years ended December 31, 2010, 2009 and 2008, these capitalized costs amounted to $971,467, $1,485,510, and $2,329,748, respectively. Capitalized costs do not include any costs related to production, general corporate overhead or similar activities. For the years ended December 31, 2010 and 2009, no interest costs were capitalized. For the years ended December 31, 2008, interest costs of $304,342 were capitalized. During the years ended December 31, 2010, 2009 and 2008, costs related to share based compensation included in development costs were $103,253, $186,058, and $375,711, respectively. During the years ended December 31, 2010, 2009 and 2008, costs related to asset retirement obligations included in development costs were $33,178, $50,444, and $1,304,766, respectively. During the years ended December 31, 2010, 2009 and 2008, currency translation adjustments included in Development costs incurred-Canada were $1,301,291, $3,633,389, and $(5,037,521), respectively. The following table discloses costs incurred in gas property acquisition, exploration and development activities for years ended December 31, 2010, 2009 and 2008.
Reserves-The following table summarizes our net ownership interests in estimated quantities of proved gas reserves and changes in net proved reserves, all of which are located in the continental U.S. Reserve estimates for natural gas contained below were prepared by DeGolyer and MacNaughton (“D&M”), independent petroleum engineers.
Users of this information should be aware that the process of estimating quantities of “proved,” “proved developed” and “proved undeveloped” natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.
(1) Aggregated revisions resulting from the new SEC guidelines which became effective December 31, 2009
The technical person primarily responsible for preparation of our internal reserve estimates and overseeing the reserve estimates prepared by D&M, an independent petroleum engineering consulting firm, is our Reservoir Engineering Manager. Our Reservoir Engineering Manager received a Bachelor of Science of Mineral Engineering (Petroleum) degree in December 1983 from the University of Alabama and is a Licensed Professional Engineer in the state of Alabama. He has worked as a petroleum engineer for approximately 24 years, including nine years with River Gas Corporation in Northport, Alabama from 1992 to 2001 and the last
nine years with GeoMet in Hoover, Alabama. He also worked briefly with Phillips Petroleum following its acquisition of River Gas Corporation. During the last 18 years, our Reservoir Engineering Manager’s primary responsibility has been methane reservoir characterization and evaluation. As such, he has had the opportunity to participate in the development and evaluation of over 2,000 coalbed methane wells located in the Black Warrior basin, the Cahaba basin, the Central Appalachian basin in West Virginia and Virginia, and the Uinta basin in Utah. Our Reservoir Engineering Manager accumulates and reviews the inputs and assumptions used by D&M to estimate our year-end reserves and assesses them for reasonableness.
Estimates of our proved reserves at December 31, 2010, 2009, and 2008 were prepared by D&M. The technical persons at D&M 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. Both the Company’s Chief Executive Officer and Chief Financial Officer are charged with the responsibility of reviewing and approving the natural gas reserve estimates prepared by D&M. Additionally, the Board of Directors formed a sub-committee of the Board with the responsibility of overseeing the reserve reporting process. This committee is comprised of three independent directors, each of whom has experience in reserve evaluations.
The reserves information in this filing 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.
Our proved natural gas reserves as of December 31, 2010, as estimated by D&M, totaled approximately 216 Bcf, an increase of approximately 3% from the approximate 209 Bcf of proved natural gas reserves at December 31, 2009, as estimated by D&M. Proved reserve estimates are based on the unweighted arithmetic average prices on the first day of each month, adjusted for regional price differentials, for the years ended December 31, 2010 and 2009, respectively. For the year ended December 31, 2010, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $4.41 per Mcf, resulting in a natural gas price of $4.49 per Mcf when adjusted for regional price differentials. For the year ended December 31, 2009, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $3.87 per Mcf, resulting in a natural gas price of $4.06 per Mcf when adjusted for regional price differentials. Natural gas prices associated with operating wells were held constant and estimates of operating expenses and capital costs based on current costs were used for the lives of the properties with no increases in the future based on inflation (in certain cases, future costs, either higher or lower than current costs, may have been used because of anticipated changes in operating condition) in accordance with the amended SEC guidelines which were effective for financial statements for periods ending on or after December 31, 2009.
Our proved reserves were 100% from coalbed methane reservoirs and were 76% developed. Approximately 64% of total year-end 2010 proved reserves are in the Pond Creek and Lasher fields in West Virginia and Virginia and 36% are in the Gurnee field in Alabama.
The following table presents the standardized measure of future net cash flows related to proved gas reserves in accordance with ASC 932. All components of the standardized measure are from proved reserves, all of which are located entirely within the continental U.S. and Canada. As prescribed by this statement, the amounts shown for December 31, 2010 and 2009 are will be calculated using the unweighted arithmetic average
of the price on the first day of each month within the twelve-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions. The amounts shown for December 31, 2008 are based on prices and costs at December 31, 2008 and assume continuation of existing economic conditions. Future income taxes are based on year-end statutory rates, adjusted for tax credits. A discount factor of 10 percent was used to reflect the timing of future net cash flows. Extensive judgments are involved in estimating the timing of future production and the costs that will be incurred throughout the remaining lives of the fields. Accordingly, the estimates of future net revenues from proved reserves and the present value thereof may not be materially correct when judged against actual subsequent results. Further, since prices and costs do not remain static, and no price or cost changes have been considered, and future production and development costs are estimated to be incurred in developing and producing the estimated proved gas reserves, the results are not necessarily indicative of the fair market value of estimated proved reserves, and the results may not be comparable to estimates disclosed by other gas producers.
Changes in standardized measure relating to proved gas reserves for the years ended December 31, 2010, 2009 and 2008 are summarized below:
For the above tables, the following natural gas pricing was utilized:
•
For the year ended December 31, 2010, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $4.41 per Mcf, resulting in a natural gas price of $4.49 per Mcf when adjusted for regional price differentials.
•
For the year ended December 31, 2009, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $3.87 per Mcf, resulting in a natural gas price of $4.06 per Mcf when adjusted for regional price differentials.
•
The natural gas price used in the valuation of natural gas reserves as of December 31, 2008 was $5.84 per Mcf ($5.71 Henry Hub spot market price for December 31, 2008, adjusted for regional price differentials).
GEOMET, INC.
QUARTERLY RESULTS OF OPERATIONS (Unaudited)
Quarterly Results of Operations. The following table sets forth the results of operations by quarter for the years ended December 31, 2010 and 2009 (in thousands):
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Management’s Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported, within the time periods specified by the SEC’s rules and forms and
include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Under the supervision and with the participation of management, our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) of the Exchange Act) as of December 31, 2010, and, based upon this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and are effective at the reasonable assurance level that information requiring disclosure is recorded, processed, summarized, and reported within the timeframe specified by the SEC’s rules and forms.
Changes in Internal Control over Financial Reporting
Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated our internal controls over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended December 31, 2010 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
Management’s Annual Report On Internal Control Over Financial Reporting
Management of GeoMet, Inc. (the “Company”), including the Company’s Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. The Company’s internal control system was designed to provide reasonable assurance to the Company’s Management and Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.
/S/ J. DARBY SERÉ
/S/ WILLIAM C. RANKIN
J. Darby Seré,
Chief Executive Officer
William C. Rankin
Chief Financial Officer
Houston, Texas
April 6, 2011
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated herein by reference to the 2011 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2010.
Item 11.
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2011 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2010.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is incorporated herein by reference to the 2011 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2010.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2011 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2010.
Item 14.
Item 14. Principal Accountant Fees and Services
The information required by this item is incorporated herein by reference to the 2011 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2010.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
List of Documents Filed as Part of this Report
(1) Financial Statements
(2) Financial Statement Schedules
None.
(3) Exhibits:
The following is a list of exhibits filed as part of this Form 10-K. Where so indicated, previously filed exhibits are incorporated herein by reference.
* Filed herewith.
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on April 6, 2011.
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrants and in the capacities on April 6, 2011.
INDEX TO EXHIBITS
* Filed herewith.