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 a decline primarily in 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. The market for natural gas is very volatile and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in natural gas prices have a significant impact on the value of our reserves and on our cash flow. 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:
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the domestic and foreign supply of natural gas;
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the price of foreign imports;
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overall domestic and global economic conditions;
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the consumption pattern of industrial consumers, electricity generators, and residential users;
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weather conditions;
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technological advances affecting energy consumption;
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domestic and foreign governmental regulations;
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proximity and capacity of gas pipelines and other transportation facilities; and
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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, 2008 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, from January 1, 2008 to February, 10, 2009, the NYMEX natural gas spot price ranged from a high of $13.54 per MMBtu to a low of $4.48 per MMBtu.
The results of higher investment in the exploration for and production of gas and oil 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 write down, as a non-cash charge to earnings, the carrying value of our properties for impairments. 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 significantly for an extended period of time, we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future indebtedness or obtain additional capital on attractive terms, all of which can affect the value of our common stock.
The deterioration of global economic and financial conditions and an prolonged decline in the price of natural gas may materially and adversely affect our business, financial condition and results of operations.
Our business, financial condition and results of operations are affected by conditions in the capital markets and the economy generally. The recent global financial crisis and worldwide economic slowdown could lead to prolonged national or global recession, which would likely reduce domestic and foreign demand for natural gas and result in lower natural gas prices. Substantial decreases in natural gas prices could have a material adverse effect on our business, financial condition and results of operations, could limit our access to liquidity and credit and could hinder our ability to fund our development program, which would limit our ability to grow or replace our proved reserves, and, eventually, our production levels.
If credit and capital markets worsen, then we may not be able to obtain funding under our current revolving credit facility or fund on acceptable terms. The inability to obtain funding could deter us from meeting our future capital needs to fund our development program.
Capital and credit markets have experienced unprecedented volatility and disruption and continue to be unpredictable. Given the current levels of market volatility and disruption, the availability of funds from those markets has diminished substantially. Further, arising from concerns about the stability of financial markets
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generally and the solvency of counterparties specifically, the cost of accessing the credit markets has increased as many lenders have raised interest rate spreads, enacted tighter lending standards or altogether ceased to provide funding to borrowers. Additionally, even if lenders continue and are able to provide funding to borrowers, interest rates may rise in the future and therefore increase the cost of outstanding borrowings that we may incur under our revolving credit facility.
Moreover, we may be unable to obtain adequate funding under our current credit facility. First, our lenders may be unwilling or unable to meet their funding commitments. Second, our borrowing base under our credit facility is redetermined semiannually. Our lenders completed their latest redetermination on March 12, 2009 and set our borrowing base at $140 million. Under the terms of the determination, our borrowing cost was increased by approximately 100 basis points and the fee on the undrawn portion of the borrowing base was increased by 12.5 basis points. Our lenders have substantial ability to reduce our borrowing base on the basis of subjective factors. If natural gas prices significantly decline for an extended period of time, our lenders could redetermine our borrowing base by evaluating our reserves in light of such lower natural gas prices. Such determination could result in a negative revision to the value of our proved reserves and a reduction of our borrowing base.
As a result of these capital and credit market conditions, we cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may not be able to meet our obligations as they come due or be required to post collateral to support our obligations, or we may not be able to implement our development program, grow our existing business through acquisitions, or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our business, financial condition and results of operations.
Changes in tax laws may impair our results of operations and adversely impact the value of our common stock.
Under current federal tax laws, we are entitled to certain deductions relating to our operations, including deductions for intangible drilling costs, manufacturing tax deductions and percentage depletion deductions. The President’s budget for the fiscal year 2010 outlines proposals to eliminate several oil and gas federal income tax incentives, including the repeal of the manufacturing tax deduction and percentage depletion allowance for oil and natural gas and expensing of intangible drilling costs. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regulations could adversely affect the amount of our taxable income or loss and could have a negative impact on the value of our common stock.
We may incur substantial costs to comply with, and demand for our products may be reduced by, climate change legislation and regulatory initiatives.
The United States Congress is considering legislation to reduce emissions of greenhouse gases and more than one-third of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. In addition, the Environmental Protection Agency has announced possible future regulation of greenhouse gas emissions under the Clean Air Act. Depending on the nature of potential regulations and legislation, such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on our business or demand for the natural gas we produce.
Index to Financial Statements 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 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:
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geological conditions;
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changes in governmental regulations and taxation;
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assumptions governing future prices;
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the amount and timing of actual production;
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future gas prices and operating costs; and
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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.
At December 31, 2008, we recorded a full cost ceiling impairment of approximately $50.7 million. The full cost ceiling calculation dictates that prices and costs in effect as of the last day of the quarter are held constant. 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.
Unless we replace our natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations, 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 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
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reserves and production and, therefore, our 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, 2008, we own leasehold interests in approximately 72,000 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:
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unexpected drilling conditions;
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title problems;
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pressure or irregularities in geologic formations;
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equipment failures or repairs;
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fires or other accidents;
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adverse weather conditions;
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reductions in natural gas prices;
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pipeline ruptures;
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regulatory permitting problems;
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inability to dispose of produced water;
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legal issues; and
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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.
We will require additional capital to fund our future activities. If we fail to obtain additional capital, we may not be able to implement fully our business plan, which could lead to a decline in reserves and production.
Historically, we have financed our business plan and operations primarily with internally generated cash flow, bank borrowings, and issuances of common stock. If our revenues decrease as a result of lower natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, need to seek additional financing. Our revolving credit facility contains covenants prohibiting our ability to incur additional indebtedness without the consent of the lenders. There can be no assurance that our lenders will provide this consent or as to the availability or terms of any additional financing. If we incur additional debt, the related risks that we now face could intensify. A higher level of debt also increases the risk that we may default on our debt obligations. Our level of debt affects our operations in several important ways, including the following:
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a portion of our cash flow from operations is used to pay interest on borrowings;
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a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes;
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a leveraged financial position would make us more vulnerable to economic downturns and could limit our ability to withstand competitive pressures; and
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any debt that we incur under our revolving credit facility will be at variable rates which makes us vulnerable to increases in interest rates.
Even if additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our projects, which in turn could lead to a possible loss of properties and a decline in our natural gas reserves.
Index to Financial Statements 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 could 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 reserve levels.
Our revolving credit facility expires in January 2011.
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.
Unlike conventional natural gas production, 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 the applicable volumetric permit limit, 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:
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we cannot obtain future permits from applicable regulatory agencies;
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water of lesser quality is produced;
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our wells produce excess water; or
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new laws and regulations require water to be disposed of in a different manner.
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. 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 agreements or non-competition agreements with any of our key employees, other than J. Darby Seré, our President and Chief Executive Officer, and William C. Rankin, our Executive Vice President and Chief Financial Officer. 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
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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 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 control 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.
Index to Financial Statements Hedging transactions may limit our potential gains.
In order to manage our interest rate exposure and natural gas price risks, we have entered into interest rate swaps and natural gas price hedging arrangements with respect to a portion of our expected production. We will most likely enter into additional hedging transactions in the future. While intended to reduce the effects of volatile interest rates and natural gas prices, such transactions may limit our potential gains or increase our potential losses.
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
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:
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results of our drilling or the results of drilling by offset operators;
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global economic recession;
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trends in our industry and the markets in which we operate;
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changes in the market price of the natural gas we sell;
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changes in financial estimates and recommendations by securities analysts;
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acquisitions and financings;
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quarterly variations in operating results;
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operating and stock price performance of other companies that investors may deem comparable to us; and
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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.
Shares eligible for future sale may cause the market price for our common stock to drop significantly, even if our business is doing well.
If our existing shareholders sell our common stock in the market, or if there is a perception that significant sales may occur, the market price of our common stock could drop significantly. In such case, our ability to raise
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additional capital in the financial markets at a time and price favorable to us might be impaired. In addition, our board of directors has the authority to issue additional shares of our authorized but unissued common stock without the approval of our shareholders, subject to certain limitations under the rules of the exchange on which our common stock is listed. Additional issuances of our common stock would dilute the ownership percentage of existing shareholders and may dilute the earnings per share of our common stock.
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.
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.
CNX Surface Use Disputes
Buchanan County Dispute. On September 12, 2008, the Virginia Supreme Court issued its decision in this matter in favor of us and PMC, reversing and remanding the matter to the Buchanan Circuit Court for further action consistent with the decision. The Court held that CNX Gas Company LLC (“CNX”) does not have the exclusive right to transport gas across the Pocahontas Mining Limited Liability Company (“PMC”) property and may not prevent uses of the PMC property that do not conflict with the exercise of CNX’s rights under its CBM lease with PMC. The effect of this ruling is that our pipeline right of way with PMC is valid.
Tazewell County Dispute. On January 19, 2007, CNX obtained a temporary injunction against our construction of the same 12-mile pipeline across 1,450 feet of a 32-acre tract in Tazewell County, Virginia. The tract of land in dispute has been owned by a large number of extended family members, from whom we have obtained approximately 81% control of the tract, either through purchases of undivided surface interests in the tract or by entering into surface use and right-of-way easement agreements. During our pipeline construction process, CNX purchased a minority undivided surface interest in the property and filed a lawsuit seeking to enjoin the construction of our Pond Creek gathering line across the property. We and CNX have since reached a resolution of this dispute. The settlement had no material impact on our financial position, results of operations, or cash flows presented herein.
CNX Antitrust Action
We filed a complaint against CNX and Island Creek Coal Company (“Island Creek”), an affiliate of CNX, in the Circuit Court of Tazewell County, Virginia on February 14, 2007, in which we sought damages arising from alleged violations of the Virginia Antitrust Act, tortious interference with contractual relations with third parties and statutory and common law conspiracy. The suit sought compensatory and consequential damages for alleged violations of the Virginia Antitrust Act, including alleged anticompetitive efforts of CNX to dominate and maintain its control over the market for the production and transportation of coalbed methane gas from the Oakwood Field in Buchanan County, Virginia and for CNX’s alleged efforts to conspire and act in concert with
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Island Creek and others to dominate and maintain control over the market for the production and transportation of coalbed methane gas from the Oakwood Field in violation of the Virginia Antitrust Act and Virginia statutory and common law. The suit also alleged CNX’s intentional interference with our existing and prospective third-party business relationships in an attempt to harm us and improve CNX’s position and corporate and financial interests. In accordance with an opinion issued by the Tazewell Circuit Court in December 2007, we have filed an amended petition that restates with specificity our claims against CNX and Island Creek, names Cardinal States Gathering Company and CONSOL Energy Inc., the ultimate parent of the other defendants, as additional defendants, and seeks actual damages of $385.6 million. We are seeking treble damages for the alleged violations of the Virginia Antitrust Act, as well as injunctive relief to prevent CNX and other parties from continuing these alleged anticompetitive activities.
Environmental and Regulatory
As of December 31, 2008, 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. Submission of Matters to a Vote of Security Holders
None.
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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 December 31, 2008 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.
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 2008. In addition, we did not sell any of our equity securities which were not registered under the Securities Act of 1933, as amended, during the fourth quarter of 2008.
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, 2008.
Index to Financial Statements
(1) In 2006, our board of directors and stockholders approved the GeoMet, Inc. 2006 Long-Term Incentive Plan under which 2,000,000 shares of our common stock were reserved for awards to be granted. In conjunction with the approval of the 2006 Plan, no additional awards have been or will be granted under our 2005 Plan; however, we will continue to issue shares of our common stock upon exercise of awards that we have previously granted. The 1,209,891 of securities remaining available for future issuance includes 242,448 shares that were reserved but not granted under our 2005 Plan.
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, 2008 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 required by the SEC and are not intended to forecast or be indicative of possible future performance of our stock.
COMPARISON OF CUMULATIVE TOTAL RETURN
Index to Financial Statements 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, 2008. The selected historical audited consolidated financial and operating data for the three years ended December 31, 2008 are derived from our audited financial statements included herein. The selected historical audited consolidated financial and operating data for the two years ended December 31, 2004 was derived from our audited financial statements which are not included herein. The table reflects a four-for-one common stock split in 2006 and prior periods have been adjusted for the stock split. You should read the following data in conjunction with “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and our consolidated 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.
Index to Financial Statements
(1) Working capital (deficit) is defined as current assets less current liabilities and is unaudited.
(2) Our natural gas sales price at December 31, 2008 was $5.84 per Mcf.
(3) Average realized price includes the effects of realized gains on derivative contracts.
(4) Based on the reserve reports prepared by DeGolyer and MacNaughton, 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.
(5) See reconciliation of non-GAAP financial measures.
Reconciliation of Non-GAAP Financial Measures
The following table shows our reconciliation of our PV-10 to our standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented in accordance with GAAP). PV-10 is our estimate of the present value of future net revenues from estimated proved natural gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our CBM gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.
Index to Financial Statements 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 control additional coalbed methane and oil and gas development rights, principally in Alabama, British Columbia, Virginia, and West Virginia. As of December 31, 2008, we control a total of approximately 213,000 net acres of coalbed methane and oil and gas development rights.
Our proved natural gas reserves as of December 31, 2008 as estimated by DeGolyer and MacNaughton, independent petroleum engineers, totaled approximately 320 Bcf, a decrease of 8.6% from the approximate 350 Bcf of proved natural gas reserves at year-end 2007. Proved reserve estimates for the current year were calculated using an unescalated natural gas price of $5.71 per MMBtu, adjusted for regional price differentials, as compared to an unescalated natural gas price in the prior year of $7.46 per MMBtu.
Our proved reserves were 100% from unconventional reservoirs, were 99% from coalbed methane and were 77% developed. The present value of proved reserves discounted at ten percent was approximately $352 million at December 31, 2008 as compared to $663 million at year-end 2007. Although reserves declined from year-end 2007, before downward revisions and a property conveyance the Company replaced approximately 296% of its production in 2008. Downward revisions totaled approximately 42 Bcf of which approximately 13 Bcf resulted from lower natural gas prices. The remaining downward revisions were primarily in the Gurnee field in Alabama, resulting from production performance issues in certain sectors of the field.
Approximately 57% of total year-end 2008 proved reserves are in the Gurnee field in Alabama and 41% are in the Pond Creek and Lasher fields in West Virginia and Virginia. The Peace River project is the first commercial coalbed methane project in British Columbia, Canada and there are no other similar producing analogies in the region. As a result, initial proved developed reserves of only 4 Bcf were booked in 2008. Similarly, our Garden City project it is the first commercial Chattanooga Shale project in Alabama, and only 2 Bcf of initial proved reserves were booked in 2008.
Impact of Current Credit Market Conditions-We believe that we are well-positioned for the current credit market environment. We have a healthy balance sheet with over $2 million in cash and a debt-to-book capital ratio of 38%. The borrowing base on our revolving credit facility was set at $140 million on March 12, 2009. Under the terms of the determination, our borrowing cost was increased by approximately 100 basis points and the fee on the undrawn portion of the borrowing base was increased by 12.5 basis points. If not extended, our credit facility will mature in January 2011. As of December 31, 2008, we were in compliance with all of the covenants in the credit agreement. All of our lenders are currently funding our borrowing requests.
Impact of Decreasing Natural Gas Prices-We account for our gas properties using the full cost method and are required to impair a full cost pool when the net capitalized costs in the pool exceed the discounted future net revenues of the proved reserves associated with the pool. Based upon the lower natural gas prices at December 31, 2008, we have reported a non-cash impairment to our U.S. full cost pool of $20 million, net of income tax. Due to limited initial proved reserve bookings in the Peace River project we also reported a non-cash
Index to Financial Statements
impairment to our Canadian full cost pool of $19 million, net of income tax. If natural gas prices at March 31, 2009 are below those prices that existed at December 31, 2008, GeoMet expects to record a non-cash impairment to the Company’s natural gas properties for the quarter then ended.
Trends
Our business is influenced by trends that affect the natural gas industry. In particular, recent declines in natural gas prices and recent economic trends could adversely affect our business, liquidity, results of operations and financial condition.
Our business is increasingly subject to the adverse trends that have taken place in the global capital markets recently. The recent events in the credit and stock markets indicate a high likelihood of a continuation of, and probable further expansion of, the economic weakness in the U.S. economy that began over one year ago. The spillover of deepening fears about our banking system may adversely impact investor confidence in us, our banking relationships, and the liquidity and financial condition of third parties with whom we conduct operations.
We expect to face the continuing challenges of weakness in the U.S. real estate market and increased mortgage delinquencies, investor anxiety over the U.S. economy, rating agency downgrades of various financial issuers, unresolved issues with structured investment vehicles, deleveraging of financial institutions and hedge funds and dislocation in the inter-bank market. If significant, continued volatility, changes in interest rates, defaults, market liquidity, declines in equity prices, and the strengthening or weakening of foreign currencies against the U.S. dollar, individually or in tandem, could have a material adverse effect on our liquidity, results of operations, financial condition or cash flows through realized losses, and impairments.
Although we expect to experience a reduction in the level of our capital spending in 2009, we believe the steps we have taken to date in response to the global slowdown in the natural gas industry will positively impact our ability to follow through with our business strategy without being forced to implement additional significant countermeasures, such as work force layoffs. Other potential steps that could be implemented in light of the current recession, if we deem it necessary, could include selling assets or entering into more joint venture agreements with industry partners to reduce our costs.
The natural gas industry is capital intensive. We make, and anticipate that we will continue to make, substantial capital expenditures in the exploration for, development and acquisition of natural gas reserves. Historically, our capital expenditures have been financed primarily with internally generated cash from operations, proceeds from bank borrowings, and industry joint venture arrangements. The continued availability of these capital sources depends upon a number of variables, including our proved reserves, the volumes of natural gas we produce from existing wells, the prices at which we sell natural gas, our ability to acquire, locate and produce new reserves, and events occurring within the global capital markets. Except for the existing revolving credit facility we have with our bank lenders, we do not currently have any agreements for any future financing and there can be no assurance as to the availability or terms of any such future financing.
Natural Gas Price Trends
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 typically fluctuate in response to relatively minor changes in supply and demand, market uncertainty, seasonal, political and other factors beyond our control. We are unable to accurately predict the prices we receive for our natural gas. Accordingly, any significant or sustained declines in natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower natural gas prices also may reduce the amount of natural gas that we can produce economically. A decline in natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our
Index to Financial Statements
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.
Operational Developments
Pond Creek-We connected 26 new infill wells to sales in 2008 giving us a total of 242 productive wells in the Pond Creek field. Net gas sales increased to 13.7 MMcf per day for the year ended December 31, 2008, as compared to 12.3 MMcf per day for the year ended December 31, 2007.
Lasher-Initial gas sales commenced on October 28, 2008. We connected a total of 18 wells to sales in 2008. Net gas sales averaged 0.1 MMcf per day for the period of October 28, 2008 through December 31, 2008.
Gurnee-We connected 11 new infill wells to sales in 2008 giving us a total of 246 productive wells in the Gurnee field. Net gas sales were unchanged at 6.1 MMcf per day for the years ended December 31, 2008 and 2007.
Garden City-In this Chattanooga shale prospect two vertical wells were re-stimulated and a horizontal well drilled in the second quarter was completed in the third quarter. These three wells were connected to sales in the third quarter with net gas sales averaging 0.1 MMcf per day through December 31, 2008. Two vertical test wells drilled in the western portion of the prospect are currently shut-in awaiting the identification of adequate water disposal and connection into a gas sales line. We are still evaluating potential water disposal solutions.
Peace River-On December 31, 2008, we commenced gas deliveries from eight wells at Peace River. We own a 50% working interest and operate the project which covers over 50,000 acres of Crown tenure. Four coreholes and twelve production wells have been drilled, targeting the Lower Cretaceous Gething coals. Average coal thickness over the acreage is 52 feet, and the average gas content is 400 cubic feet per ton.
Property Conveyance and Dispute
We had previously entered into an agreement to sell our interests in a property, subject to a preferential right to purchase held by another party, which the other party subsequently exercised. A dispute arose as to whether the preferential right to purchase applied to all the interests we owned in this property or just the working interests. We filed a declaratory judgment action asserting that the preferential right to purchase applied only to the working interests, and that we were entitled to retain all remaining interests we owned in the property. Following a partial agreement with the other party, we assigned all our remaining interests in the property to that party, effective July 1, 2008. On October 17, 2008, the 116th Judicial District Court of Dallas issued an order requiring us to pay $575,000 to the other party in final settlement of the issue. We have subsequently reached a settlement with the other party in the amount of $475,000, which has been accrued as a liability as of December 31, 2008. The proved reserves conveyed represented less than 1% of our total proved reserves and the related production was approximately 900 Mcf per day.
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 experiences 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 financial statements included
Index to Financial Statements
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 DeGolyer and MacNaughton, 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 “basis” or location differential, held constant over the life of the reserves. In addition, subsequent to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), 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.
At December 31, 2008, the carrying value of the Company’s gas properties in the U.S. exceeded the full cost ceiling limitation by $19,959,547, net of income tax of $12,087,937, based upon a natural gas price of
Index to Financial Statements
approximately $5.84 per Mcf in effect at that date. A decline in prices received for gas sales or an increase in operating costs or reductions in estimated economically recoverable quantities could result in the recognition of an impairment of our gas properties in a future period. In the year ended December 31, 2008, we recognized an impairment of our gas properties of $19,959,547, net of income tax of $12,087,937.
At December 31, 2008, the carrying value of the Company’s gas properties in Canada exceeded the full cost ceiling limitation by $18,686,273 (no income tax effect as Canadian income taxes are fully valued), based upon a natural gas price of approximately $5.20 per Mcf in effect at that date. A decline in prices received for gas sales or an increase in operating costs or reductions in estimated economically recoverable quantities could result in the recognition of an impairment of our gas properties in a future period. In the year ended December 31, 2008, we recognized an impairment of our gas properties of $18,686,273.
If natural gas prices at March 31, 2009 are below those prices that existed at December 31, 2008, GeoMet expects to record a non-cash impairment to the Company’s natural gas properties for the quarter then ended.
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 SFAS 143, 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 the SFAS No. 109, Accounting for Income Taxes (“SFAS 109”) as clarified by FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109 (“FIN 48”). 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 SFAS 109, 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.
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”).
The Company adopted the provisions of FIN 48 on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109,
Index to Financial Statements
“Accounting for Income Taxes”, 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 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.
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 2009 and 2010. We also entered into interest rate swap agreements to hedge interest rates associated with a portion of our variable rate debt through 2010. 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 financial statements in accordance with SFAS l33. 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 SFAS 133, as amended, all our derivative instruments are recorded on the balance sheet at fair market value and changes in the fair market 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 cash flow hedges in accordance with SFAS 133.
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.
Stock-Based Compensation-We follow the fair value recognition provisions of SFAS No. 123(R), Share-Based Payment (“SFAS 123(R)”), using the prospective transition method. The application of SFAS 123(R) 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
Index to Financial Statements
assumptions could be highly uncertain. For share-based awards outstanding prior to the adoption of SFAS 123(R), 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.
Fair Value Measurement-In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 is effective for fiscal years beginning after November 15, 2007. Effective January 1, 2008, we adopted SFAS 157, which provides a framework for measuring fair value under GAAP. SFAS 157 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. SFAS 157 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 SFAS 157 in Note 6-Derivative Instruments and Hedging Activities. The FASB has also issued Staff Position FAS 157-2 (“FSP 157-2”), which delays the effective date of SFAS 157 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 SFAS 157 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 SFAS 157 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 SFAS 157 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 will adopt SFAS 157 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 financial statements related to the implementation of SFAS 157 for our existing non-financial assets and liabilities.
Index to Financial Statements Natural Gas Production-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, 2008, 2007 and 2006. 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.
Index to Financial Statements Results of Operations
Year Ended December 31, 2008 compared with Year Ended December 31, 2007
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 $18.6 million, or 37%, to $68.3 million compared to the prior year. The increase in gas sales was a result of both increased gas prices and production. Production increased 5% and average gas prices, excluding hedging transactions, increased 32%. The $18.6 million increase in gas sales consisted of a $2.3 million increase in production and a $16.3 million increase in average prices. The increase in production was principally attributable to the continued development activities at our Pond Creek and Gurnee fields.
Lease operating expenses. Lease operating expenses increased by $0.8 million, or 6%, to $14.8 million compared to the prior year. The $0.8 million increase in lease operating expenses consisted of $0.6 million increase in production and $0.2 million increase in costs.
Compression expense. Compression expense increased by $0.5 million, or 19%, to $3.1 million compared to the same period in the prior year. The increase in compression expense consisted of a $0.1 million increase in production and a $0.4 million increase in costs. The $0.4 million increase in costs was primarily due to an increase in repair and maintenance expenses for the compressors in our Pond Creek field.
Transportation expense. Transportation expense decreased by $1.2 million, or 46%, to $1.4 million compared to the prior year period. The decrease was primarily due to lower transportation expenses resulting from the commencement of transportation on our own system from the Pond Creek field and the temporary release of a portion of our firm capacity commitments related to our Pond Creek field.
Production taxes. Production taxes increased by $1.0 million, or 84%, to $2.1 million compared to the prior year period. The increase in production taxes was due to the phase-in of state taxes on production of natural gas in our Pond Creek field, higher gas prices and increased production.
Index to Financial Statements Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $1.5 million, or 16%, to $10.6 million compared to the prior year period. The depreciation, depletion and amortization increase consisted of a $0.4 million increase in production and a $1.1 million increase in the depletion rate.
Impairment of gas properties. At December 31, 2008, the carrying value of the Company’s oil and gas properties exceeded the full cost ceiling limitation by approximately $50.7 million. For the year ended December 31, 2007, no such write-down was recorded.
General and administrative. General and administrative expenses increased by $0.1 million, or 1%, to $9.4 million compared to the prior year period. The primary driver for the increased general and administrative expenses was increased office expense, share based awards and investor relation expense, offset by a decrease in employee bonuses.
Realized losses (gains) on derivative contracts. Realized losses on derivative contracts were $0.5 million in the current year period as compared to $3.9 million of realized gains in the prior year period. Realized losses represent net cash flow settlements paid to the counterparty while realized gains represent net cash flow settlement paid to us from the counterparty. Realized losses occur when natural gas prices or the derivative index price exceeds the derivative ceiling price. Conversely, realized gains occur when natural gas prices go below the derivative floor price.
Unrealized (gains) losses from the change in market value of open derivative contracts. Unrealized gains on open derivative contracts were $5.0 million in the current year period as compared to a $3.0 million in unrealized losses in the prior year period. Unrealized losses and gains are non-cash transactions that occur when the corresponding natural gas derivative contract asset or liability is marked to market at the end of each reporting period.
Interest expense (net of amounts capitalized). Interest expense (net of amounts capitalized) decreased by $0.3 million, or 7%, to $4.8 million compared to the prior year period. Gross interest expense for the period was $5.1 million net of $0.3 million capitalized. Gross interest expense decreased 11% from the prior year period due to lower interest rates, while capitalized interest decreased 48% from the prior year period due to the deferral of certain capital projects.
Income tax benefit. Income tax benefit was $0.7 million in the current year as compared to an expense of $3.0 million in the prior year period. The effective tax rate for the 2008 was 3.1% as compared to 37.4% for 2007. The decrease in the effective tax rate was due to the full valuation of the deferred income tax benefit of $6.6 million related to our Canadian impairment of gas properties recorded in 2008.
Discontinued operations. In September of 2007, we discontinued the third party marketing business and second reportable segment which had been created in connection with the consolidation of Shamrock Energy LLC, a variable interest entity under FIN 46 (R) on August 1, 2006. The consolidation of the variable interest entity had no impact on our net income (loss) due to the 100% minority interest to Shamrock Energy LLC. On January 1, 2007, we acquired Shamrock Energy LLC as a wholly owned subsidiary and the consolidation of this wholly owned subsidiary had an insignificant impact on our net income (loss). As a result of exiting our third party marketing business, we are treating these activities as a discontinued operation for all the periods presented.
Index to Financial Statements Results of Operations
Year Ended December 31, 2007 compared with Year Ended December 31, 2006
NM-Not Meaningful
Gas sales. Gas sales increased by $4.9 million, or 11%, to $49.7 million compared to the prior year. The increase in gas sales was a result of increased production, partially offset by lower average gas prices. Production increased 14% while average gas prices, excluding hedging transactions, decreased 3%. The $4.9 million increase in gas sales consisted of a $6.5 million increase in production and a $1.6 million decrease in average prices. The increase in production was principally attributable to our Gurnee and Pond Creek development activities.
Lease operating expenses. Lease operating expenses increased by $2.4 million, or 21% to $14.0 million. The $2.4 million increase in lease operating expenses consisted of $1.7 million increase in production and $0.7 million increase in costs. The increase in costs is related to an increase in well service activities from the prior year period.
Compression and transportation expenses. Compression and transportation expenses increased by $0.7 million, or 16%, to $5.2 million ($2.6 million each for both compression and transportation). The $0.7 million increase was comprised of a $0.5 million increase in compression expenses due to increased production and a $0.2 million increase in transportation expenses due to increased production offset by a decrease in the actual per Mcf transportation expenses due to the certain gas transported on our own system in 2007.
Production taxes. Production taxes increased by $0.127 million, or 12%, to $1.164 million. The production taxes increase of $0.127 million was primarily due to increased production, partially offset by lower average gas prices.
Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $1.2 million, or 15%, to $9.1 million. The depreciation, depletion and amortization increase of $1.2 million resulted from the increase in production. There were no significant changes in the depletion rate in 2007.
General and administrative. General and administrative expenses increased by $2.7 million, or 42%, to $9.3 million. The increase in general and administrative expenses was a result of increases in employee expenses (15%), professional services (94%), director and investor relations expenses (139%), insurance expense (74%) and office expenses and business taxes (6%). The largest dollar increase was in employee expenses and professional services that resulted from the increased audit, Sarbanes Oxley, tax and legal services. The increase
Index to Financial Statements
in general and administrative expenses was a result of expanding the overhead structure to support our growth and increased costs of being a public company.
Realized gains on derivative contracts. Realized gains on derivative contracts increased by $2.8 million to $3.9 million compared to a gain of $1.1 million in the prior period. Realized losses represent net cash flow settlements paid to the counterparty while realized gains represent net cash flow settlement paid to us from the counterparty. Realized losses occur when natural gas prices or the derivative index price exceeds the derivative ceiling price. Conversely, realized gains occur when natural gas prices go below the derivative floor price.
Unrealized (gains) losses from the change in market value of open derivative contracts. Unrealized (gains) losses from the change in market value of open derivative contracts generated a $3.0 million loss as compared to a $16.9 million gain in the prior 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. Unrealized gains are recognized when the fair values of derivative assets increase or the fair value of derivative liabilities decrease. Unrealized losses are recognized when the fair values of derivative assets decrease or the fair value of derivative liabilities increase. The $3.0 million loss was a result of increased future natural gas prices.
Interest expense (net of amounts capitalized). Interest expense (net of amounts capitalized) increased by $2 million, or 64%, to $5.1 million. The increase was primarily due to higher outstanding debt and higher interest rates. Capitalized interest totaled $0.6 million and $1.0 for the years ended December 31, 2007 and 2006, respectively.
Income tax expense. Income tax expense decreased by $7.9 million to $3.0 million. The decrease in income tax expense for the period was due to decreased pretax income compared to the prior period. In addition, the effective tax rate decreased for the year to 37% from 39% in the comparable prior period. The principal driver for the difference in the effective tax rate was due to lower state income taxes resulting from state apportionment factor shifting.
Discontinued operations. In September of 2007, we discontinued the third party marketing business and second reportable segment which had been created in connection with the consolidation of Shamrock Energy LLC, a variable interest entity under FIN 46 (R) on August 1, 2006. The consolidation of the variable interest entity had no impact on our net income (loss) due to the 100% minority interest to Shamrock Energy LLC. On January 1, 2007, we acquired Shamrock Energy LLC as a wholly owned subsidiary and the consolidation of this wholly owned subsidiary had an insignificant impact on our net income (loss). As a result of exiting our third party marketing business, we are treating these activities as a discontinued operation for all the periods presented.
Liquidity and Capital Resources
Cash Flows and Liquidity
Cash flows from operations for the year ended December 31, 2008 and 2007 were $33.0 million and $17.5 million, respectively. Cash flow provided by operations for the year ended December 31, 2008 of $33.0 million combined together with $20.5 million (net) borrowed from our revolving credit facility were sufficient to fund our cash basis capital expenditures of $52.8 million.
As of December 31, 2008, we had a working capital deficit of approximately $1.4 million, a decrease of $0.7 million from the working capital deficit of $2.1 million at December 31, 2007. At December 31, 2008, we had adequate cash flows from operating activities and credit availability to fund our working capital deficits.
Index to Financial Statements The following table is a summary of our capital expenditures on an accrual basis by category:
Our capital expenditure budget for 2009 will be funded from our estimated operating cash flows. If our cash flows are not sufficient to fund all of our estimated capital expenditures, we may reduce our capital budget. The amount and timing of our expenditures are subject to change based upon market conditions, results of expenditures 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 borrowing base redeterminations under our revolving credit facility. Based on current gas price projections, we expect capital expenditures to be less than the $24.1 million capital budget we previously announced.
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 volume of initial and subsequent natural gas production volumes.
Based upon current expectations, we believe that we will have adequate resources from cash flows provided by operations and from proceeds from our revolving credit facility borrowings to fund our 2008 capital expenditures and other working capital needs.
Currently, there is an unprecedented uncertainty in the financial markets. The uncertainty in the market brings additional potential risks to us. The risks include less availability and higher costs of additional credit, potential counterparty defaults, and further commercial bank failures. Although the financial institutions in our bank group appear to be strong, there are some that have been and could be considered take-over candidates. Although we have no indication that any such transactions would impact our current credit facility, the possibility does exist. Financial market disruptions may impact our ability to collect trade receivables. We constantly monitor the credit worthiness of our customers. We believe that our current group of customers are sound and represent no abnormal business risk.
If natural gas prices decrease from their current levels for an extended period, our ability to finance our planned capital expenditures could be affected negatively, consistent with our intention to keep our capital expenditures in line with our estimated operating cash flows, further reduction in spending may be necessary. Furthermore, amounts available for borrowing under our revolving credit facility are largely dependent on our level of estimated proved reserves and current natural gas prices. If either our estimated proved reserves or natural gas prices decrease, amounts available to us to borrow under our revolving credit facility could be negatively affected. If our cash flows are less than anticipated, amounts available for borrowing under our revolving credit facility are reduced or we are unable to sell equity at acceptable prices, we may be forced to defer planned capital expenditures.
Index to Financial Statements Natural Gas Price Risk and Related Hedging Activities.
We are exposed to natural gas price risk associated with downward movements in natural gas prices. Natural gas prices have experienced volatility in recent years in response to changes in the supply and demand for natural gas and market uncertainty. The markets and prices for natural gas depend upon factors beyond our control and changes in these prices could adversely affect our revenue and cash flows. These factors include demand for natural gas, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, the availability of imported natural gas, actions taken by foreign oil and gas producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption and the extent of governmental regulation and taxation.
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 movements. Our price risk management policy strictly prohibits the use of derivatives for speculative positions.
We enter into hedging transactions that increase our statistical probability of achieving our targeted level of cash flows and at times hedge forward for periods of more than two years. We generally limit the amount of these hedges during any period to no more than 50% to 60% of the then expected gas production for such future periods. We have historically used swaps, costless collars and three-way costless collars in our hedging activities. 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. We have accounted for these transactions using the mark-to-market accounting method. Generally, we incur accounting losses during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctuations in our consolidated statement of operations.
We believe that the use of derivative instruments does not expose us to material risk. However, the use of derivative instruments may materially affect our financial position and results of operations as a result of changes in the estimated market value of our natural gas derivatives. Nevertheless, we believe that use of these instruments will not have a material adverse effect on our cash flows.
The following (gains) losses on our hedging instruments included in the consolidated statements of operations are as follows:
Index to Financial Statements Commodity Price Risk and Related Hedging Activities.
At December 31, 2008, we had the following natural gas collar positions:
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 SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS l33”). 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 (loss) 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, 2008, we had the following interest rate swaps:
(1) The floating rate paid by the counterparty is the British Bankers’ Association LIBOR rate.
For the year ended December 31, 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 credit agreement and the collateral for the outstanding borrowings under our credit 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 credit agreement.
The application of SFAS 157 currently applies to our derivative instruments. Under the provisions of SFAS 157, 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. SFAS 157 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 at December 31, 2008. 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 price curve and volatility estimates were compiled from sources that include NYMEX settlements and
Index to Financial Statements
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 a yield curve based on Money Market rates and Interest Rate swaps, extrapolate a forecast of future 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.
Based on the use of observable market inputs, we have designated these types of instruments as Level 2 for SFAS 157 reporting purposes. The fair value of our derivative instruments at December 31, 2008 and 2007 were as follows:
In June 2006, we entered into a credit agreement with Bank of America, N.A., as agent, and other lenders. Availability under our credit agreement is subject to a borrowing base, which was $180 million at December 31, 2008. As of December 31, 2008, our credit agreement provided for interest to accrue at a rate calculated, at our option, at either the adjusted base rate (which is the greater of the agent’s base rate or the federal funds rate plus one half of one percent) or the London Interbank Offered Rate (LIBOR) plus a margin of 1.00% to 2.00%, based on borrowing base usage. Under the terms of the determination, our borrowing cost was increased by approximately 100 basis points and the fee on the undrawn portion of the borrowing base was increased by 12.5 basis points. Borrowings under our credit agreement are secured by first priority liens on substantially all of our assets including equity interests in our subsidiaries. All outstanding borrowings under our credit agreement become due and payable on January 6, 2011.
We are subject to financial covenants requiring maintenance of a minimum current ratio and a minimum interest coverage ratio. Our ratio of consolidated current assets (adjusted for unrealized (gains) losses on derivative contracts and borrowing availability) to our consolidated current liabilities is not permitted to be less than 1 to 1 as of the end of any fiscal quarter, and our ratio of consolidated EBITDA for the four preceding quarters at the end of each fiscal quarter to the sum of our consolidated net interest expense for the same period plus letter of credit fees accruing during such quarter is not permitted to be less than 2.75 to 1. Consolidated EBITDA, as defined in the amended credit agreement, excludes other non-cash charges deducted in determining net income (loss), which would include unrealized losses from the change in the market value of open derivative contracts. In addition, we are 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. 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,
Index to Financial Statements
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 facility. Any acceleration in the repayment of our indebtedness or related foreclosure could adversely affect our business. As of December 31, 2008, we were in compliance with all of the covenants in the credit agreement.
At December 31, 2008, we had $116.5 million outstanding under our revolving credit facility. For the year ended December 31, 2008, interest on the borrowings averaged 4.56% per annum. Borrowing availability at December 31, 2008 was $63.5 million.
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, 2008, beginning January 1, 2009 (in thousands):
(1) Maturities based on the June 2006 amended bank credit agreement terms, which extended the maturity date to January 6, 2011.
(2) Assumes an annual rate on a 30-day LIBOR of 0.99% plus the current 1.50% margin for a total interest rate of 2.49%, net of swap recoveries.
(3) As of December 31, 2008, we had a liability for unrecognized tax benefits of approximately $273K. 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.
Discontinued Operations
As of September 30, 2007, we discontinued the third party marketing business and second reportable segment which had been created in connection with the consolidation of Shamrock Energy LLC, a variable interest entity under FIN 46(R) on August 1, 2006. The consolidation of the variable interest entity had no impact on our net income (loss) due to the 100% minority interest to Shamrock Energy LLC. On January 1, 2007, we acquired Shamrock Energy LLC as a wholly owned subsidiary and the consolidation of this wholly owned subsidiary had an insignificant impact on our net income (loss). As a result, we are treating our third party marketing activities as a discontinued operation for all the periods presented.
The marketing activities of Shamrock Energy LLC have been transitioned to GeoMet, Inc without disruption in the marketing of our gas, and we do not expect to incur significant liabilities or sell any assets in connection with discontinuing this business. As a result, the discontinued operations have an insignificant impact on our cash flows.
Index to Financial Statements Recent Accounting Pronouncements
In December 2007, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standards No. 141R, “Business Combinations (Revised 2007)” (“SFAS 141R”), which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141R is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of an entity’s fiscal year that begins on or after Dec. 15, 2008. We will evaluate the impact of SFAS 141R on our consolidated financial statements for any potential business combinations subsequent to Jan. 1, 2009.
On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities-Including an Amendment of FASB 115” (“SFAS 159”). This standard permits an entity to measure financial instruments and certain other items at estimated fair value. Most of the provisions of SFAS 159 are elective; however, the amendment to FASB 115, “Accounting for Certain Investments in Debt and Equity Securities,” applies to all entities that own trading and available-for-sale securities. The fair value option created by SFAS 159 permits an entity to measure eligible items at fair value as of specified election dates. The fair value option (a) may generally be applied instrument by instrument, (b) is irrevocable unless a new election date occurs, and (c) must be applied to the entire instrument and not to only a portion of the instrument. SFAS 159 is effective as of the beginning of the first fiscal year that begins after November 15, 2007. Effective January 1, 2008, we adopted SFAS 159. We did not elect the fair value option for any of our assets or liabilities that did not already require such treatment under other authoritative literature.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS 160”). SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 requires that changes in a parent’s ownership interest in a subsidiary be reported as an equity transaction in the consolidated financial statements when it does not result in a change in control of the subsidiary. When a change in a parent’s ownership interest results in deconsolidation, a gain or loss should be recognized in the consolidated financial statements. SFAS 160 must be applied prospectively as of January 1, 2009, except for the presentation and disclosure requirements, which are required to be applied retrospectively for all periods presented. The adoption of SFAS 160 did not have a material impact on our results of operations, cash flows or financial positions; however, it could impact future transactions entered into by us.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133” (“SFAS 161”). This standard changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We are currently assessing the impact of SFAS 161 on our disclosures relating to derivative instruments and hedging activities. The statement only provides for enhanced disclosure. Therefore, adoption will have no impact on our financial position or results of operations.
In May 2008, the FASB issued Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” The new standard is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities. Statement 162 establishes that the GAAP hierarchy should be directed to entities because it is the entity (not its auditor) that is responsible for selecting accounting
Index to Financial Statements
principles for financial statements that are presented in conformity with GAAP. Statement 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” We do not expect this guidance to have a significant impact on us.
In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”), which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the net income allocation in computing basic net income per share under the two class method prescribed under SFAS 128, “Earnings per Share”. FSP 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and, to the extent applicable, must be applied retrospectively by adjusting all prior-period net income per share data to conform to the provisions of the standard. The adoption of FSP EITF 03-6-1 is not expected to have a material effect on the Company’s earnings per share calculations.
In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The provisions of this final ruling will become effective for disclosures in our Annual Report on Form 10-K for the year ended December 31, 2009.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk. Our major commodity price risk exposure is to the prices received for our natural gas production. Realized prices received for our natural gas production are the spot prices applicable to natural gas. Prices received for natural gas are volatile and unpredictable and are beyond our control. At December 31, 2008, a 10% decrease in the prices received for natural gas production would have had an approximate $2.7 million impact on our revenues.
Interest Rate Risk. We have long-term debt subject to the risk of loss associated with movements in interest rates. At December 31, 2008, we had $116.5 million outstanding under our revolving credit facility. For the year ended December 31, 2008, interest on the borrowings averaged 4.56% per annum. Borrowing availability at December 31, 2008 was $63.5 million. 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 at December 31, 2008, a 1% increase in market interest rates would have increased interest expense and negatively impacted our annual cash flows by approximately $0.8 million. $40 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. The effect of changes in the exchange rate may impact our revenues or expenses, as well as the costs of our proved properties. We 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.
Index to Financial Statements Item 8.
Item 8. Financial Statements and Supplementary Data
GEOMET, INC. AND SUBSIDIARIES
Index to Financial Statements REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of GeoMet, Inc.
Houston, TX
We have audited the accompanying consolidated balance sheets of GeoMet, Inc. and subsidiaries (the “Company”) as of December 31, 2008 and 2007, 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, 2008. We also have audited the Company’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GeoMet, Inc. and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
As discussed in Note 1 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board Interpretations No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109” on January 1, 2007.
/s/ DELOITTE & TOUCHE LLP
Houston, TX
March 12, 2009
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying Notes to Consolidated Audited Financial Statements.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31,
See accompanying Notes to Consolidated Audited Financial Statements.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME (LOSS)
See accompanying Notes to Consolidated Audited Financial Statements.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying Notes to Consolidated Audited Financial Statements.
Index to 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 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., Hudson’s Hope Gas, Ltd and Shamrock Energy LLC. 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 financial statements and the reported amounts of revenues and expenses during the reporting period. Our most significant financial estimates are based on remaining 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”). 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.
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 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.
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NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
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 natural gas prices in effect as of the balance sheet date and adjusted for “basis” or location differential, held constant over the life of the reserves, as allowed by the guidelines of the SEC. In addition, subsequent to the adoption of Statement of Financial Accounting Standard (“SFAS”) No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”), 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.
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 SFAS 143, 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.
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.
Furniture and fixtures
7 years
Automobiles
3 years
Machinery and equipment
5 years
Software and computer equipment
3 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.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Notes Receivable Included in Stockholders’ Equity-We have loaned money to officers and 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, 2008 and 2007 are solely attributable to employees as all notes due from executive officers were paid in January 2006 in accordance with the rules and regulations of the SEC. See Note 12 for additional information regarding repayment.
Income Taxes-We record our income taxes using an asset and liability approach in accordance with the provisions of the SFAS No. 109, Accounting for Income Taxes (“SFAS 109”) as clarified by Financial Accounting Standards Board (“FASB”) Interpretation No. 48, Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109 (“FIN 48”). 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 SFAS 109, 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.
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”).
The Company adopted the provisions of FIN 48 on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS 109, 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 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 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
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
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, 2008 and 2007 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. At December 31, 2008, we have recorded an allowance for doubtful accounts receivable of $60,848 related to other revenue and not a purchaser of our natural gas. At December 31, 2007, we did not record an allowance for doubtful accounts receivable as management had assessed accounts receivable to be recoverable. Risks with respect to derivative assets as of December 31, 2008 arise from cash settlements due to us from our derivative counterparties. We have primarily one purchaser of our natural gas production. 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.
Fair Value of Financial Instruments-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 9 for the fair values of the receivable and debt.
Operating Fees and Other-Operating fees and other for the years ended December 31, 2008 and 2007 include produced water disposal fees. Operating fees and other for the years ended December 31, 2006 include fees from operating coal bed methane gas fields from other owners.
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, 2008, 2007 and 2006 of $2,329,748, $1,991,760, and $1,174,149, 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, 2008, 2007 and 2006, we capitalized $304,342, $587,884 and $1,037,576 of interest, respectively. See Unevaluated Properties above for additional information on the criteria for including costs in unevaluated properties.
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 2009 and 2010. We also entered into an interest rate swap agreement to hedge interest rates associated with a portion of our variable rate debt through 2010. Typically, these derivative instruments require payments to (receipts from)
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
counterparties based on specific indices as required by the derivative agreements. These transactions are recorded in our financial statements in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS l33”). 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 SFAS 133, 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 SFAS 133.
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.
Foreign Currency Translation-For subsidiaries 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. Our only foreign subsidiary is our Canadian subsidiary, Hudson’s Hope Gas, Ltd.
Stock-Based Compensation-Prior to January 1, 2006, stock-based employee compensation was accounted for under the intrinsic value method of Accounting Principles Bulletin No. 25, Accounting for Stock Issued to Employees (“APB 25”). The exercise price of the options granted was equal to the estimated market value of our common stock at grant date, and therefore, no compensation costs have been recognized. We used the income method on a semi-annual basis to estimate the market value of our common stock at grant date.
Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS No. 123(R), Share-Based Payment (“SFAS 123(R)”), using the prospective transition method. The application of SFAS 123(R) 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.
Discontinued Operations-We use the criteria in SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”) and EITF 03-13, Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations (EITF 03-13), to determine whether our components that are being disposed of or are classified as held for sale are required to be reported as discontinued operations in the Consolidated Statements of Operations. To qualify as a discontinued operation under SFAS 144, the component being disposed of must have clearly distinguishable operations and cash flows.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Additionally, pursuant to EITF 03-13, we must not have significant continuing involvement in the operations after the disposal (i.e. we must not have the ability to influence the operating or financial policies of the disposed component) and cash flows of the operations being disposed of must have been eliminated from GeoMet’s ongoing operations (i.e. we do not expect to generate significant direct cash flows from activities involving the disposed component after the disposal transaction is completed). Assuming both preceding conditions are met, the related results of operations for the current and prior periods, including any related impairments, are reflected as Income From Discontinued Operations, net of income tax, in the Consolidated Statements of Operations.
Fair Value Measurement-In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 is effective for fiscal years beginning after November 15, 2007. Effective January 1, 2008, we adopted SFAS 157, which provides a framework for measuring fair value under GAAP. SFAS 157 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. SFAS 157 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 SFAS 157 in Note 6 - Derivative Instruments and Hedging Activities. The FASB has also issued Staff Position FAS 157-2 (“FSP 157-2”), which delays the effective date of SFAS 157 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 SFAS 157 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 SFAS 157 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 SFAS 157 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 will adopt SFAS 157 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 financial statements related to the implementation of SFAS 157 for our existing non-financial assets and liabilities.
Note 3-Recent Accounting Pronouncements
In December 2007, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standards No. 141R, “Business Combinations (Revised 2007)” (“SFAS 141R”), which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS 141R is to be applied prospectively to business combinations
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
for which the acquisition date is on or after the beginning of an entity’s fiscal year that begins on or after Dec. 15, 2008. We will apply SFAS 141R in our consolidated financial statements for any business combinations subsequent to Jan. 1, 2009.
On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities-Including an Amendment of FASB 115” (“SFAS 159”). This standard permits an entity to measure financial instruments and certain other items at estimated fair value. Most of the provisions of SFAS 159 are elective; however, the amendment to FASB 115, “Accounting for Certain Investments in Debt and Equity Securities,” applies to all entities that own trading and available-for-sale securities. The fair value option created by SFAS 159 permits an entity to measure eligible items at fair value as of specified election dates. The fair value option (a) may generally be applied instrument by instrument, (b) is irrevocable unless a new election date occurs, and (c) must be applied to the entire instrument and not to only a portion of the instrument. SFAS 159 is effective as of the beginning of the first fiscal year that begins after November 15, 2007. Effective January 1, 2008, we adopted SFAS 159. We did not elect the fair value option for any of our assets or liabilities that did not already require such treatment under other authoritative literature.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (“SFAS 160”). SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 requires that changes in a parent’s ownership interest in a subsidiary be reported as an equity transaction in the consolidated financial statements when it does not result in a change in control of the subsidiary. When a change in a parent’s ownership interest results in deconsolidation, a gain or loss should be recognized in the consolidated financial statements. SFAS 160 must be applied prospectively as of January 1, 2009, except for the presentation and disclosure requirements, which are required to be applied retrospectively for all periods presented. The adoption of SFAS 160 did not have a material impact on our results of operations, cash flows or financial positions; however, it could impact future transactions entered into by us.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133” (“SFAS 161”). This standard changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We are currently assessing the impact of SFAS 161 on our disclosures relating to derivative instruments and hedging activities. The statement only provides for enhanced disclosure. Therefore, adoption did not have any impact on our financial position or results of operations.
In May 2008, the FASB issued Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” The new standard is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities. Statement 162 establishes that the GAAP hierarchy should be directed to entities because it is the entity (not its auditor) that is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. Statement 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” We do not expect this guidance to have a significant impact on us.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
In June 2008, the FASB issued FASB Staff Position No. EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”), which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the net income allocation in computing basic net income per share under the two class method prescribed under SFAS 128, “Earnings per Share”. FSP 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and, to the extent applicable, must be applied retrospectively by adjusting all prior-period net income per share data to conform to the provisions of the standard. The adoption of FSP EITF 03-6-1 is not expected to have a material effect on the Company’s earnings per share calculations.
In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to revise the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technological advances. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (a) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserve audit and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices. The provisions of this final ruling will become effective for disclosures in our Annual Report on Form 10-K for the year ended December 31, 2009.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Note 4-Net (Loss) Income Per Share
Net (Loss) Income Per Share of Common Stock-Basic (loss) income per share is calculated by dividing net (loss) income by the weighted average number of shares of common stock outstanding during the period. No dilution for any potentially dilutive securities is included. Fully diluted net (loss) income per share assumes the conversion of all potentially dilutive securities and is calculated by dividing net (loss) income by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Dilutive (loss) income per share 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 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. Diluted net income per share for the year ended December 31, 2007 excluded the effect of outstanding options to purchase 640,477 shares because the average market price at December 31, 2007 was less than the exercise price. Diluted net income per share for the year ended December 31, 2006 excluded the effect of outstanding options to purchase 245,405 shares because the average market price at December 31, 2006 was less than the exercise price.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Note 5-Note Receivable
We have an unsecured note receivable of $271,736 and $298,936 as of December 31, 2008 and 2007, respectively, from a third party included in other non-current assets. The note requires payment on a semi-monthly basis, including interest at 8.25%, of $2,168. The fair value of the receivable was $224,700 and $338,000 at December 31, 2008 and 2007, 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 SEC. Under the full cost 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 limitation test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. The ceiling limitation 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 “basis” or location differential, held constant over the life of the reserves. In addition, subsequent to the adoption of SFAS 143, 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.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
At December 31, 2008, the carrying value of the Company’s gas properties in the U.S. exceeded the full cost ceiling limitation by $19,959,547, net of income tax of $12,087,937, based upon a natural gas price of approximately $5.84 per Mcf in effect at that date. A decline in prices received for gas sales or an increase in operating costs or reductions in estimated economically recoverable quantities could result in the recognition of an impairment of gas properties in a future period. In the year ended December 31, 2008, the Company recognized an impairment of gas properties of $19,959,547, net of income tax of $12,087,937. There was no impairment of gas properties recognized in 2007 and 2006.
At December 31, 2008, the carrying value of the Company’s gas properties in Canada exceeded the full cost ceiling limitation by $18,686,273 (no income tax effect as Canadian income taxes are offset by a full valuation allowance), based upon a natural gas price of approximately $5.20 per Mcf in effect at that date. A decline in prices received for gas sales or an increase in operating costs or reductions in estimated economically recoverable quantities could result in the recognition of an impairment of gas properties in a future period. In the year ended December 31, 2008, the Company recognized an impairment of gas properties of $18,686,273. There was no impairment of gas properties recognized in 2007 and 2006.
If natural gas prices at March 31, 2009 are below those prices that existed at December 31, 2008, GeoMet expects to record a non-cash impairment to the Company’s natural gas properties for the quarter then ended.
Property Conveyance and Dispute
We had previously entered into an agreement to sell our interests in a property, subject to a preferential right to purchase held by another party, which the other party subsequently exercised. A dispute arose as to whether the preferential right to purchase applied to all the interests we owned in this property or just the working interests. We filed a declaratory judgment action asserting that the preferential right to purchase applied only to the working interests, and that we were entitled to retain all remaining interests we owned in the property. Following a partial agreement with the other party, we assigned all our remaining interests in the property to that party, effective July 1, 2008. On October 17, 2008, the 116th Judicial District Court of Dallas issued an order requiring us to pay $575,000 to the other party in final settlement of the issue. We have subsequently reached a settlement with the other party in the amount of $475,000, which has been accrued as a liability as of December 31, 2008. The proved reserves conveyed represented less than 1% of our total proved reserves.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
The following table provides a summary of the capitalized cost of our gas properties as of December 31, 2008 and 2007, by the year in which the costs were incurred.
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, 2008 and 2007.
Revisions in estimates of our asset retirement liability totaling $1,040,014 were due primarily to specific lease agreement requirements related to plugging and abandonment of certain wells and were capitalized in the full cost pool of our gas properties.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Note 8-Derivative Instruments and Hedging Activities
The energy markets have historically been very volatile, and there can be no assurance that natural gas prices will not be subject to wide fluctuations in the future. 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 movements. Our price risk management policy strictly prohibits the use of derivatives for speculative positions.
We enter into hedging transactions that increase our statistical probability of achieving our targeted level of cash flows and at times hedge forward for periods of more than two years. We generally limit the amount of these hedges during any period to no more than 50% to 60% 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. 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 statement of operations.
We believe that the use of derivative instruments does not expose us to material risk. However, the use of derivative instruments may materially affect our financial position and results of operations as a result of changes in the estimated market value of our natural gas derivatives. Nevertheless, we believe that use of these instruments will not have a material adverse effect on our cash flows.
The following (gains) losses on our hedging instruments included in the consolidated statements of operations are as follows:
Commodity Price Risk and Related Hedging Activities.
At December 31, 2008, we had the following natural gas collar positions:
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
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 SFAS 133. 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, 2008, we had the following interest rate swaps:
(1) The floating rate paid by the counterparty is the British Bankers’ Association LIBOR rate.
For the year ended December 31, 2008, there was 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 credit agreement and the collateral for the outstanding borrowings under our credit 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 credit agreement.
The application of SFAS 157 currently applies to our derivative instruments. Under the provisions of SFAS 157, 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. SFAS 157 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 at December 31, 2008. 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 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 a yield curve based on Money Market rates and Interest Rate swaps, extrapolate a forecast of future 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
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
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.
Based on the use of observable market inputs, we have designated these types of instruments as Level 2 for SFAS 157 reporting purposes. The fair value of our derivative instruments at December 31, 2008 and 2007 were as follows:
Note 9-Long-Term Debt
At December 31, 2008, we had a borrowing base of $180 million, maturing January 6, 2011. On March 12, 2009, the Company’s bank syndicate approved a borrowing base of $140 million after completing its year-end borrowing base determination. The next regular borrowing base determination, which will be based on a June 30, 2009 reserve report prepared by the Company, is scheduled to be complete on or before December 16, 2009. Under the terms of the determination, our borrowing cost was increased by approximately 100 basis points and the fee on the undrawn portion of the borrowing base was increased by 12.5 basis points. Our revolving credit facility permits us to borrow and repay amounts as needed based on the available borrowing base as determined in the credit agreement. The revolving credit facility is secured by substantially all of our gas properties and the capital stock of our subsidiaries. The borrowing base under the revolving credit facility is based upon the reserve valuation of our gas properties as of June 30 and December 31 of each year and other factors deemed relevant by the lenders, including Bank of America as agent. The lenders may also request one additional borrowing base re-determination in any fiscal year.
As of December 31, 2008, we had $116.5 million of borrowings outstanding under our revolving credit facility, resulting in a borrowing availability of $63.5 million under our $180 million borrowing base. For the years ended December 31, 2008 and 2007 we borrowed $115 million and $83 million, respectively, and made payments of $94.5 million and $47 million, respectively, under the revolving credit facility. The outstanding balances on the revolving credit facility bear interest at the bank’s adjusted base rate, which is the bank’s base rate of at least the Federal Funds Rate plus 0.5%, or the adjusted LIBOR rate, plus a margin of 1.00% to 2.00%, based on borrowing base usage. The rates at December 31, 2008 and 2007, excluding the effect of our interest rate swaps, were 2.49% and 6.29%, respectively.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
The following is a summary of our long-term debt at December 31, 2008 and 2007:
We are subject to certain restrictive financial and non-financial covenants under the credit agreement, including a minimum current ratio, adjusted for unrealized (gains) losses on derivative contracts and borrowing availability, of 1.0 to 1.0, and a rate of consolidated EBITDA to interest expense of up to 2.75 to 1.0, both as defined in the credit agreement. As of December 31, 2008, we were in compliance with all of the financial covenants in the credit agreement.
The following were maturities of long-term debt for each of the next five years at December 31, 2008:
The fair value of long-term debt at December 31, 2008 and 2007 is approximately $92,485,449 and $83,384,209, respectively. SFAS 157 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 S&P credit rating of a comparable company to ours and the stated interest rates of the debt instruments included our long-term debt, both at December 31, 2008.
Note 10-Discontinued Operations
As of September 30, 2007, we discontinued the third-party marketing business and second reportable segment which had been created in connection with the consolidation of Shamrock Energy LLC, a variable interest entity under FIN 46(R) on August 1, 2006. The consolidation of the variable interest entity had no impact
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
on our net income (loss) due to the 100% minority interest to Shamrock Energy LLC. On January 1, 2007, we exercised our purchase option and acquired 100% of Shamrock Energy LLC, our discontinued gas marketing subsidiary. Over 99% of the net assets acquired were current, approximated their fair value and were equal to zero. Shamrock Energy LLC was a low margin business and as a result it did not have a significant impact on our results of operations. The acquisition was accounted for as a purchase in accordance with SFAS 141, whereby the purchase price of the net assets acquired was allocated to those net assets based on their fair value. Goodwill was not recorded because the purchase price approximated the fair value of the net assets acquired.
As a result of exiting the third-party marketing business, we are treating these activities as a discontinued operation for all the periods presented. Results for activities reported as discontinued operations were as follows:
Statement of Operations Data (for the year ended December 31):
Balance Sheet Data:
Note 11-Income Taxes
We record our income taxes using an asset and liability approach in accordance with the provisions of the FASB Statement No. 109, Accounting for Income Taxes, as clarified by FIN 48. This results in the recognition of deferred tax assets and liabilities using estimated effective tax rates for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities using enacted tax rates at the end of the period. Under FASB 109, the effect of a change in tax rates of deferred tax assets and liabilities is recognized in the year of the enacted change.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
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. 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 Section 382 of the Internal Revenue Code. We have a significant deferred tax asset associated with net operating loss carryforwards (NOL’s). It is more likely than not that we will use the NOL’s in the U.S. to offset current tax liabilities in future years.
Our effective tax rate differs from the federal statutory rate primarily due to losses in Canada that we are unable to benefit from and state income taxes. The Canadian losses, as well as certain state losses, are fully reserved because it is more likely than not that we will not use those NOL’s to offset current tax liabilities in future years.
Uncertain Tax Positions
We adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, we identified $269,900 of unrecognized tax benefits, largely related to depletion methods used in years prior to 2006 from net deferred tax assets. There was no cumulative effect adjustment to retained earnings, our financial condition or results of operations as a result of implementing FIN 48 principally due to the size of our NOL’s. The amount of unrecognized tax benefits has not materially changed and as of December 31, 2008 and 2007 was $272,600.
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.
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. As of the date of adoption of FIN 48, we did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the years ended December 31, 2008 and 2007.
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, 2009.
For tax reporting purposes, we have federal and state NOL’s of approximately $78,075,499 and $5,890,879, respectively, at December 31, 2008 that are available to reduce future taxable income. If not utilized, the federal carryforwards would begin to expire in 2022. Certain immaterial portions of the state NOL’s will expire prior to 2022. Our long-term deferred tax asset does not include $7.2 million in deferred tax asset related to our Canadian operations and gas properties as it has been fully valued in accordance with SFAS 109.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
An analysis of our deferred taxes follows:
Federal income tax expense from continuing operations for each of the years ended December 31, 2008, 2007, and 2006 was different than the amount computed using the Federal statutory rate for the following reasons:
The effective tax rate in 2008 of 3.07% was due to the full valuation of the deferred income tax benefit of $6,565,447 related to our Canadian impairment of gas properties recorded in 2008.
The following components of the federal income tax expense for the years ended December 31, 2008, 2007 and 2006 are as follows:
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Note 12-Common Stock
At December 31, 2008 and 2007, there were 39,049,684 shares and 38,962,359 shares, respectively, of common stock outstanding, including 10,432 shares and 7,828 shares, respectively, of treasury stock held by the Company. For the years ended December 31, 2008 and 2007, a total of 68,605 and 105,565 shares, respectively, of common stock were issued upon the exercise of stock options granted under our 2005 Stock Option Plan. In March 2008, we issued 253,806 shares of restricted stock to key employees, as well as 5 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. Additionally, for the years ended December 31, 2008 and 2007, 45,032 shares and 31,500 shares of restricted stock, respectively, were forfeited. No shares of restricted stock were forfeited for the year ended December 31, 2006. For the year ended December 31, 2006, a total of 637,026 shares of common stock were issued upon the exercise of stock options.
Effective January 24, 2006, our board of directors approved a four-for-one common stock split and increased our authorized capital stock from 40,000,000 shares of common stock at January 1, 2006 to 135,000,000 shares of capital stock, consisting of 125,000,000 shares of common stock and 10,000,000 shares of preferred stock. Prior periods have been adjusted for the stock split.
On January 30, 2006 and February 7, 2006, we completed private equity offerings of an aggregate 10,250,000 shares of our common stock, consisting of 2,317,023 shares issued by us and 7,932,977 shares sold by certain of our existing stockholders, to qualified institutional buyers exempt from registration under the Securities Act. We received aggregate consideration of approximately $28.0 million, or $12.09 per share. We did not receive any proceeds from the shares sold by certain of our existing stockholders. In addition, we received approximately $17.5 million from certain of the selling stockholders for repayment of loans from us, including accrued and unpaid interest thereon. We used the net proceeds from this private equity offering, together with the proceeds from the repayment of certain of the selling stockholders’ loans, to repay a portion of the borrowings under our revolving credit facility and for general corporate purposes.
On July 27, 2006, we registered for re-sale with the SEC the 10,250,000 shares of common stock issued in the private equity offering discussed above. Also on July 27, 2006, we sold 5,750,000 shares of our common stock under an underwritten initial public offering. Our initial public offering closed on August 2, 2006, and the price per share was $10.00. We received net proceeds of approximately $52.6 million from our initial public offering after deducting estimated offering expenses and underwriting discounts and commissions. We used the net proceeds from the initial public offering to reduce outstanding borrowings under our revolving credit facility.
Note 13-Share-Based Awards
Effective January 1, 2006, we adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment”, using the prospective transition method. 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.
As of December 31, 2008, we have two stock-based award plans authorized, 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, although we will continue to issue shares of our common stock upon exercise of awards previously granted under the 2005 Stock Option Plan.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
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 2,000,000 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 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 issued to our directors vest immediately.
In March 2007, we granted 168,975 share-based stock option awards and in June 2007 we granted 138,000 restricted stock awards to certain of our non-executive employees with time vesting criteria. In September 2007 we granted 219,279 share-based stock option awards and we also granted 30,145 restricted stock awards, including 20,145 with performance-based vesting to our named executive officers and two other officers. In November 2007 we granted 19,841 incentive stock options, 20,000 restricted stock awards and 40,159 non-qualified stock options to an officer that vest on March 15, 2010. In March 2008, we granted 164,604 restricted stock awards with time vesting criteria to certain key employees, including our four executive officers. Additionally, we granted 89,202 restricted stock awards with performance vesting criteria to our four executive officers and two other officers. We also granted 18,720 shares of common stock to our independent directors, representing 50% of their annual retainer. In September 2008, we granted 46,694 restricted stock awards with time vesting criteria to certain key employees.
During 2007, we recorded a compensation expense accrual of $526,576 which was allocated among lease operating expenses ($118,830), general and administrative expenses ($118,830), and capitalized to unevaluated gas properties ($215,093). During 2008, we recorded a compensation expense accrual of $941,697 which was allocated among lease operating expenses ($53,737), general and administrative expenses ($512,680), and capitalized to unevaluated gas properties ($375,280). The future compensation cost of all the outstanding awards is $ 1,714,327 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 1.41 years.
For the year ended December 31, 2008, no stock options were granted. For the year ended December 31, 2007, the significant assumptions used in determining the compensation costs included a dividend yield of 0%, expected volatility of 40.20%, risk-free interest rate of 4.02%, an expected term of 4.5 years, forfeiture rates from 5% to 15%, and no expected dividends. For the year ended December 31, 2006, the significant assumptions used in determining the compensation costs included a dividend yield of 0%, expected volatility of 36.95%, risk-free interest rate of 4.87%, an expected term of 4.5 years, forfeiture rates from 5% to 15%, and no expected dividends.
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
Incentive Stock Options
The table below summarizes incentive stock option activity for the year ended December 31, 2008:
During the year ended December 31, 2008, no incentive stock options were granted. The weighted average grant-date fair value of incentive stock options granted during the years 2007 and 2006 was $2.32 and $4.85, respectively. The total intrinsic value of incentive stock options exercised during the years ended December 31, 2008, 2007, and 2006 was $0.6 million, $0.5 million and $5.2 million, respectively.
Non-Qualified Stock Options
The table below summarizes non-qualified stock option activity for the year ended December 31, 2008:
During the years ended December 31, 2008 and 2007, no non-qualified stock options were granted or exercised. The total intrinsic value of non-qualified stock options exercised during the year ended December 31, 2006 was $1.7 million. During the year ended December 31, 2008, no non-qualified stock options were granted. The weighted average grant-date fair value of non-qualified stock options granted during the years 2007 and 2006 was $1.18 and $4.96, respectively.
Restricted Stock Awards
The table below summarizes non-vested restricted stock awards activity for the year ended December 31, 2008:
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
On April 18, 2007, 4,083 shares of restricted stock vested. The fair value of the shares that vested on that date was $35,604. On June 15, 2008, 20,800 shares of restricted stock vested. The fair value of the shares that vested on that date was $186,576. On September 20, 2008, 5,591 shares of restricted stock vested. The fair value of the shares that vested on that date was $33,266. On September 24, 2008, 2,000 shares of restricted stock vested. The fair value of the shares that vested on that date was $11,760. There has been no vesting of restricted stock other than described above.
Note 14-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 total contributions up to a total of five percent of their annual compensation. Our matching contribution vests evenly over three years. Our contributions to the Plan for the years ended December 31, 2008, 2007 and 2006 were $264,305, $170,062 and $137,357, respectively.
Note 15-Commitments and Contingencies
Litigation-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.
CNX Surface Use Disputes
Buchanan County Dispute. On September 12, 2008, the Virginia Supreme Court issued its decision in this matter in favor of us and PMC, reversing and remanding the matter to the Buchanan Circuit Court for further action consistent with the decision. The Court held that CNX Gas Company LLC (“CNX”) does not have the exclusive right to transport gas across the Pocahontas Mining Limited Liability Company (“PMC”) property and may not prevent uses of the PMC property that do not conflict with the exercise of CNX’s rights under its CBM lease with PMC. The effect of this ruling is that our pipeline right of way with PMC is valid.
Tazewell County Dispute. On January 19, 2007, CNX obtained a temporary injunction against our construction of the same 12-mile pipeline across 1,450 feet of a 32-acre tract in Tazewell County, Virginia. The tract of land in dispute has been owned by a large number of extended family members, from whom we have obtained approximately 81% control of the tract, either through purchases of undivided surface interests in the tract or by entering into surface use and right-of-way easement agreements. During our pipeline construction process, CNX purchased a minority undivided surface interest in the property and filed a lawsuit seeking to enjoin the construction of our Pond Creek gathering line across the property. We and CNX have since reached a resolution of this dispute. The settlement had no material impact on our financial position, results of operations, or cash flows presented herein.
CNX Antitrust Action
We filed a complaint against CNX and Island Creek Coal Company (“Island Creek”), an affiliate of CNX, in the Circuit Court of Tazewell County, Virginia on February 14, 2007, in which we sought damages arising from alleged violations of the Virginia Antitrust Act, tortious interference with contractual relations with third parties and statutory and common law conspiracy. The suit sought compensatory and consequential damages for alleged violations of the Virginia Antitrust Act, including alleged anticompetitive efforts of CNX to dominate
Index to Financial Statements GEOMET, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AUDITED FINANCIAL STATEMENTS-(Continued)
and maintain its control over the market for the production and transportation of coalbed methane gas from the Oakwood Field in Buchanan County, Virginia and for CNX’s alleged efforts to conspire and act in concert with Island Creek and others to dominate and maintain control over the market for the production and transportation of coalbed methane gas from the Oakwood Field in violation of the Virginia Antitrust Act and Virginia statutory and common law. The suit also alleged CNX’s intentional interference with our existing and prospective third-party business relationships in an attempt to harm us and improve CNX’s position and corporate and financial interests. In accordance with an opinion issued by the Tazewell Circuit Court in December 2007, we have filed an amended petition that restates with specificity our claims against CNX and Island Creek, names Cardinal States Gathering Company and CONSOL Energy Inc., the ultimate parent of the other defendants, as additional defendants, and seeks actual damages of $385.6 million. We are seeking treble damages for the alleged violations of the Virginia Antitrust Act, as well as injunctive relief to prevent CNX and other parties from continuing these alleged anticompetitive activities.
Environmental and Regulatory
As of December 31, 2008, 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 2014. Future minimum lease commitments as of December 31, 2008 under non-cancelable operating leases having remaining terms in excess of one year are as follows:
Total rental expenses under operating leases were approximately $2,005,994, $1,542,660 and $1,591,027 for the years ended December 31, 2008, 2007 and 2006, respectively.
Transportation Contracts-As of December 31, 2008, under the following firm transportation contracts, we can transport maximum daily volumes of (1) 7,000 MMBtu’s continuing until October 31, 2010, (2) 10,000 MMBtu’s continuing until October 31, 2011, (3) 15,000 MMBtu’s continuing until April 1, 2022, and (4) 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, 2008, the maximum commitment remaining under the transportation contracts is approximately $17.7 million.
Index to Financial Statements SUPPLEMENTARY FINANCIAL AND OPERATING INFORMATION ON GAS
EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
This supplemental schedule provides unaudited information pursuant to SFAS No. 69, Disclosures About Oil and Natural Gas Producing Activities, (“SFAS 69”) and certain other information.
Capitalized Costs-Capitalized costs and accumulated depreciation, depletion, amortization 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, 2008, 2007 and 2006 are summarized below.
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, 2008, 2007 and 2006, these capitalized costs amounted to $2,329,748, $1,991,760 and $1,174,148, respectively. Capitalized costs do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs in 2007 include a $3.0 million purchase price adjustment for a 2004 acquisition. For the years ended December 31, 2008, 2007 and 2006, interest costs of $304,342, $587,884 and $1,037,576, respectively, were capitalized.
Capitalized Costs Incurred
The following table discloses costs incurred in gas property acquisition, exploration and development activities for the years ended December 31, 2008, 2007 and 2006.
Index to Financial Statements 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, 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.
The following table presents the standardized measure of future net cash flows related to proved gas reserves in accordance with SFAS 69. 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 are based on prices and costs at December 31, 2008, 2007 and 2006, 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
Index to Financial Statements
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, 2008, 2007 and 2006 are summarized below:
The weighted average prices of gas used with the above tables at December 31, 2008, 2007 and 2006 were $5.84, $7.58 and $5.63 per Mcf, respectively.
Index to Financial Statements 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, 2008 and 2007 (in thousands):
Index to Financial Statements Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. 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, 2008, and, based upon this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in providing reasonable assurance 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 year ended December 31, 2008 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, 2008.
/s/ J. DARBY SERÉ
/s/ WILLIAM C. RANKIN
J. Darby Seré,
Chief Executive Officer
William C. Rankin
Chief Financial Officer
Houston, Texas
March 12, 2009
Index to Financial Statements Item 9B.
Item 9B. Other Information
Certain of our non-employee directors and our largest stockholder may from time to time have investments in other exploration and production companies that may compete with us. Section 122(17) of the Delaware General Corporation Law permits a Delaware corporation, such as GeoMet, to renounce by action of its board of directors any interest or expectancy of the corporation in certain opportunities, effectively eliminating the ambiguity in a Delaware corporation’s ability to do so in advance arising out of prior Delaware case law. Under corporate law concepts of fiduciary duty, our officers and directors generally have a duty to disclose to us opportunities that are related to our business and are generally prohibited from pursuing those opportunities unless we determine that we are not going to pursue them.
On March 12, 2009, we entered into a Business Opportunities Agreement with two of our non-employee directors and our largest shareholder. This agreement provides that so long as any of these persons, which we refer to as “Designated Parties,” is serving as a member of our board of directors, we renounce in advance any interest or expectancy in any business opportunity, transaction or other matter in and that involves any aspect of the oil and gas exploration, exploitation, development and production other than:
•
any business opportunity that is brought to the attention of a Designated Party solely in such person’s capacity as a director of our company and with respect to which, at the time of such presentment, no other Designated Party has independently received notice or otherwise identified such opportunity; or
•
any business opportunity that is identified by a Designated Party solely through the disclosure of information by or on behalf of us.
Under the terms of this Business Opportunities Agreement as approved by our board of directors, a Designated Party will not be required to inform us of a business opportunity that he becomes aware of so long as he did not become aware of the opportunity as a consequence of serving as a member of our board of directors. Furthermore, the Designated Party will be permitted to pursue that opportunity even if it is competitive with our business. This Business Opportunities Agreement does not prohibit us from pursuing any business opportunity to which we have renounced any interest or expectancy. It will provide the Designated Parties and their respective affiliates with some certainty that opportunities that they independently pursue will not be required to be first offered to us.
The form of Business Opportunities Agreement is attached to this Form 10-K as exhibit 10.20.
Index to Financial Statements 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 2009 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2008. Pursuant to Item 401(b) of Regulation S-K, the information required by this item with respect to our executive officers is set forth in Part I of this report.
Item 11.
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2009 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2008.
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 2009 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2008.
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 2009 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2008.
Item 14.
Item 14. Principal Accountant Fees and Services
The information required by this item is incorporated herein by reference to the 2009 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2008.
Index to Financial Statements 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.
[to add “Business Opportunities Agreement”]
Index to Financial Statements
Index to Financial Statements
* Filed herewith.
Index to Financial Statements 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 March 12, 2009.
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 March 12, 2009.
Signature
Capacity
/s/ J. DARBY SERÉ
J. Darby Seré
Chairman of the Board, President, Chief Executive Officer (Principal Executive Officer)
/s/ WILLIAM C. RANKIN
William C. Rankin
Executive Vice President, Chief Financial Officer (Principal Financial Officer)
/s/ TONY OVIEDO
Tony Oviedo
Vice President, Chief Accounting Officer and Controller
/s/ J. HORD ARMSTRONG, III
J. Hord Armstrong, III
Director
/s/ JAMES C. CRAIN
James C. Crain
Director
/s/ STANLEY L. GRAVES
Stanley L. Graves
Director
/s/ CHARLES D. HAYNES
Charles D. Haynes
Director
/s/ W. HOWARD KEENAN, JR.
W. Howard Keenan, Jr.
Director
/s/ PHILIP G. MALONE
Philip G. Malone
Director
Index to Financial Statements INDEX TO EXHIBITS
Index to Financial Statements
* Filed herewith.