ITEM 1A. RISK FACTORS
You should carefully consider the following risk factors as well as the other information contained or incorporated by reference in this report, as these important factors, among others, could cause our actual results to differ from our expected or historical results. It is not possible to predict or identify all such factors. Consequently, you should not consider any such list to be a complete statement of all of our potential risks or uncertainties.
A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition, cash flow, liquidity or results of operations and our ability to meet our capital expenditure obligations and financial commitments and to implement our business strategy.
Our business is heavily dependent upon the prices of, and demand for, oil and natural gas. Historically, the prices for oil and natural gas have been volatile and are likely to remain volatile in the future. Prices for oil remained relatively strong in 2012, but our realized natural gas prices continued to decline in 2012, reaching a thirteen year low of $2.03 per Mcf in the second quarter of 2012. The continued growth in production of natural gas in the United States has increased supply and resulted in high natural gas storage inventories. As a result, natural gas prices continue to face downward pressures.
The prices we receive for our oil and natural gas production and the level of such production will be subject to wide fluctuations and depend on numerous factors beyond our control, including the following:
•
the domestic and foreign supply of oil and natural gas;
•
weather conditions;
•
the price and quantity of imports of oil and natural gas;
•
political conditions and events in other oil-producing and natural gas-producing countries, including embargoes, hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
•
the actions of the Organization of Petroleum Exporting Countries, or OPEC;
•
domestic government regulation, legislation and policies;
•
the level of global oil and natural gas inventories;
•
technological advances affecting energy consumption;
•
the price and availability of alternative fuels; and
•
overall economic conditions.
If the decline in the price of natural gas that first started in 2008 continues through 2013, the lower prices will adversely affect:
•
our revenues, profitability and cash flow from operations;
•
the value of our proved oil and natural gas reserves;
•
the economic viability of certain of our drilling prospects;
•
our borrowing capacity; and
•
our ability to obtain additional capital.
We have entered into certain oil price hedging arrangements on certain of our anticipated sales in 2013. In the future we may enter into additional hedging arrangements in order to reduce our exposure to price risks. Such arrangements would limit our ability to benefit from increases in oil and natural gas prices.
The recent recession could have a material adverse impact on our financial position, results of operations and cash flows.
The oil and gas industry is cyclical and tends to reflect general economic conditions. The United States and other countries have been in a recession which could continue through 2013 and beyond, and the capital markets have experienced significant volatility. The recession has had an adverse impact on demand and pricing for oil and natural gas. A continuation of the recession could have a further negative impact on oil and natural gas prices. Our operating cash flows and profitability will be significantly affected by declining oil and natural gas prices. Further declines in oil and natural gas prices may also impact the value of our oil and gas reserves, which could result in future impairment charges to reduce the carrying value of our oil and gas properties and our marketable securities. Our future access to capital could be limited due to tightening credit markets and volatile capital markets. If our access to capital is limited, development of our assets may be delayed or limited, and we may not be able to execute our growth strategy.
Our future production and revenues depend on our ability to replace our reserves.
Our future production and revenues depend upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we must continue our acquisition and drilling activities. We cannot assure you, however, that our acquisition and drilling activities will result in significant additional reserves or that we will have continuing success drilling productive wells at low finding and development costs. Furthermore, while our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return.
A prospect is a property in which we own an interest or have operating rights and that has what our geoscientists believe, based on available seismic and geological information, to be an indication of potential oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial additional evaluation and interpretation. There is no way
to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. The analysis that we perform using data from other wells, more fully explored prospects and/or producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling prospects. If we drill additional unsuccessful wells, our drilling success rate may decline and we may not achieve our targeted rate of return.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as restrict our access to our oil and gas reserves.
Hydraulic fracturing is an essential and common practice that is used to stimulate production of oil and natural gas from dense subsurface rock formations such as shale and tight sands. We routinely apply hydraulic fracturing techniques in completing our wells. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the oil or natural gas to flow to the wellbore. The use of hydraulic fracturing is necessary to produce commercial quantities of oil and natural gas from many reservoirs including the Haynesville shale, Bossier shale, Eagle Ford shale, Wolfcamp shale, Bone Spring, Cotton Valley and other tight natural gas and oil reservoirs. Substantially all of our proved oil and gas reserves that are currently not producing and our undeveloped acreage require hydraulic fracturing to be productive. All of the wells being drilled by us in 2013 utilize hydraulic fracturing in their completion. We estimate we will incur approximately $178.0 million for hydraulic fracturing services in connection with our 2013 drilling and completion program.
The use of hydraulic fracturing in our well completion activities could expose us to liability for negative environmental effects that might occur. Although we have not had any incidents related to hydraulic fracturing operations that we believe have caused any negative environmental effects, we have established operating procedures to respond and report any unexpected fluid discharge which might occur during our operations, including plans to remediate any spills that might occur. In the event that we were to suffer a loss related to hydraulic fracturing operations, our insurance will be net of a $25,000 deductible and our ability to recover costs will be limited to a total aggregate policy limit of $26.0 million, which may or may not be sufficient to pay the full amount of our losses incurred.
Drilling and completion activities are typically regulated by state oil and natural gas commissions. Our drilling and completion activities are conducted primarily in Louisiana and Texas. Texas adopted a law in June 2012 requiring disclosure to the Railroad Commission of Texas and the public of certain information regarding the components used in the hydraulic-fracturing process. Several proposals are before the United States Congress that, if implemented, would subject the process of hydraulic fracturing to regulation under the Safe Drinking Water Act. At the direction of Congress, the EPA is currently conducting an extensive, multi-year study into the potential effects of hydraulic fracturing on underground sources of drinking water, and the results of that study have the potential to impact the likelihood or scope of future legislation or regulation.
Potential changes to US federal tax regulations, if passed, could have an adverse effect on us.
The United States Congress continues to consider imposing new taxes and repeal of many tax incentives and deductions that are currently used by independent oil and gas producers. Examples of changes being considered that would impact us are: elimination of the ability to fully deduct intangible
drilling costs in the year incurred, repeal of the manufacturing tax deduction for oil and gas companies, increasing the geological and geophysical cost amortization period, and implementation of a fee on non-producing leases located on federal lands. If these proposals are enacted, our current income tax liability will increase, potentially significantly, which would have a negative impact on our cash flow from operating activities. A reduction in operating cash flow could require us to reduce our drilling activities. Since none of these proposals have yet to be included in new legislation, we do not know the ultimate impact they may have on our business.
Our debt service requirements could adversely affect our operations and limit our growth.
We had $1.3 billion in debt as of December 31, 2012, and our ratio of total debt to total capitalization was approximately 59%.
Our outstanding debt will have important consequences, including, without limitation:
•
a portion of our cash flow from operations will be required to make debt service payments;
•
our ability to borrow additional amounts for working capital, capital expenditures (including acquisitions) or other purposes will be limited; and
•
our debt could limit our ability to capitalize on significant business opportunities, our flexibility in planning for or reacting to changes in market conditions and our ability to withstand competitive pressures and economic downturns.
In addition, future acquisition or development activities may require us to alter our capitalization significantly. These changes in capitalization may significantly increase our debt. Moreover, our ability to meet our debt service obligations and to reduce our total debt will be dependent upon our future performance, which will be subject to general economic conditions and financial, business and other factors affecting our operations, many of which are beyond our control. If we are unable to generate sufficient cash flow from operations in the future to service our indebtedness and to meet other commitments, we will be required to adopt one or more alternatives, such as refinancing or restructuring our indebtedness, selling material assets or seeking to raise additional debt or equity capital. We cannot assure you that any of these actions could be effected on a timely basis or on satisfactory terms or that these actions would enable us to continue to satisfy our capital requirements.
Our bank credit facility contains a number of significant covenants. These covenants will limit our ability to, among other things:
•
borrow additional money;
•
merge, consolidate or dispose of assets;
•
make certain types of investments;
•
enter into transactions with our affiliates; and
•
pay dividends.
Our failure to comply with any of these covenants could cause a default under our bank credit facility and the respective indentures governing our senior notes. A default, if not waived, could result in acceleration of our indebtedness, in which case the debt would become immediately due and payable. If this occurs, we may not be able to repay our debt or borrow sufficient funds to refinance it given the current status of the credit markets. Even if new financing is available, it may not be on terms that are acceptable to us. Complying with these covenants may cause us to take actions that we otherwise would not take or not take actions that we otherwise would take.
The unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel and oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
Our industry has experienced a shortage of drilling rigs, equipment, supplies and qualified personnel in recent years as the result of higher demand for these services. Costs and delivery times of rigs, equipment and supplies have been substantially greater than they were several years ago. In addition, demand for, and wage rates of, qualified drilling rig crews have escalated due to the higher activity levels. Shortages of drilling rigs, equipment or supplies or qualified personnel in the areas in which we operate could delay or restrict our exploration and development operations, which in turn could adversely affect our financial condition and results of operations because of our concentration in those areas.
Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
Our future success will depend on the success of our exploration and development activities. Exploration activities involve numerous risks, including the risk that no commercially productive natural gas or oil reserves will be discovered. In addition, these activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their costs, unsuccessful wells can hurt our efforts to replace production and reserves.
Our business involves a variety of operating risks, including:
•
unusual or unexpected geological formations;
•
fires;
•
explosions;
•
blow-outs and surface cratering;
•
uncontrollable flows of natural gas, oil and formation water;
•
natural disasters, such as hurricanes, tropical storms and other adverse weather conditions;
•
pipe, cement, or pipeline failures;
•
casing collapses;
•
mechanical difficulties, such as lost or stuck oil field drilling and service tools;
•
abnormally pressured formations; and
•
environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.
If we experience any of these problems, well bores, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations.
We could also incur substantial losses as a result of:
•
injury or loss of life;
•
severe damage to and destruction of property, natural resources and equipment;
•
pollution and other environmental damage;
•
clean-up responsibilities;
•
regulatory investigation and penalties;
•
suspension of our operations; and
•
repairs to resume operations.
We pursue acquisitions as part of our growth strategy and there are risks in connection with acquisitions.
Our growth has been attributable in part to acquisitions of producing properties and companies. We expect to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms we consider favorable. However, we cannot assure you that suitable acquisition candidates will be identified in the future, or that we will be able to finance such acquisitions on favorable terms. In addition, we compete against other companies for acquisitions, and we cannot assure you that we will successfully acquire any material property interests. Further, we cannot assure you that future acquisitions by us will be integrated successfully into our operations or will increase our profits.
The successful acquisition of producing properties requires an assessment of numerous factors beyond our control, including, without limitation:
•
recoverable reserves;
•
exploration potential;
•
future oil and natural gas prices;
•
operating costs; and
•
potential environmental and other liabilities.
In connection with such an assessment, we perform a review of the subject properties that we believe to be generally consistent with industry practices. The resulting assessments are inexact and their accuracy uncertain, and such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is made.
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geologic characteristics or geographic location than our existing properties. While our current operations are focused in the East Texas/North Louisiana, South Texas and West Texas regions, we may pursue acquisitions or properties located in other geographic areas.
We operate in a highly competitive industry, and our failure to remain competitive with our competitors, many of which have greater resources than we do, could adversely affect our results of operations.
The oil and natural gas industry is highly competitive in the search for and development and acquisition of reserves. Our competitors often include companies that have greater financial and personnel resources than we do. These resources could allow those competitors to price their products and services more aggressively than we can, which could hurt our profitability. Moreover, our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to close transactions in a highly competitive environment.
Our competitors may use superior technology that we may be unable to afford or which would require costly investment by us in order to compete.
If our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow
them to enjoy technological advances and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. All of these factors may inhibit our ability to acquire additional prospects and compete successfully in the future.
Substantial exploration and development activities could require significant outside capital, which could dilute the value of our common shares and restrict our activities. Also, we may not be able to obtain needed capital or financing on satisfactory terms, which could lead to a limitation of our future business opportunities and a decline in our oil and natural gas reserves.
We expect to expend substantial capital in the acquisition of, exploration for and development of oil and natural gas reserves. In order to finance these activities, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of non-strategic assets or other means. The issuance of additional equity securities could have a dilutive effect on the value of our common shares, and may not be possible on terms acceptable to us given the current volatility in the financial markets. The issuance of additional debt would require that a portion of our cash flow from operations be used for the payment of interest on our debt, thereby reducing our ability to use our cash flow to fund working capital, capital expenditures, acquisitions, dividends and general corporate requirements, which could place us at a competitive disadvantage relative to other competitors. Additionally, if our revenues decrease as a result of lower oil or natural gas prices, operating difficulties or declines in reserves, our ability to obtain the capital necessary to undertake or complete future exploration and development programs and to pursue other opportunities may be limited, which could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could result in a decline in our oil and natural gas reserves.
If oil prices decline and natural gas prices remain low or continue to decline, we may be required to write-down the carrying values and/or the estimates of total reserves of our oil and natural gas properties, which would constitute a non-cash charge to earnings and adversely affect our results of operations.
Accounting rules applicable to us require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur non-cash charges in the future, which could have a material adverse effect on our results of operations in the period taken. We may also reduce our estimates of the reserves that may be economically recovered, which could have the effect of reducing the total value of our reserves. Such a reduction in carrying value could impact our borrowing ability and may result in accelerating the repayment date of any outstanding debt.
Our reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve
estimate depends on the quality of available data, production history and engineering and geological interpretation and judgment. Because all reserve estimates are to some degree imprecise, the quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas prices may all differ materially from those assumed in these estimates. The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves is only estimated and should not be construed as the current market value of the oil and natural gas reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Any future downward revisions could adversely affect our financial condition, our borrowing ability, our future prospects and the value of our common stock.
As of December 31, 2012, 38% of our total proved reserves were undeveloped and 8% were developed non-producing. These reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced at the time periods we have planned, at the costs we have budgeted, or at all. As a result, we may not find commercially viable quantities of oil and natural gas, which in turn may result in a material adverse effect on our results of operations.
If we are unsuccessful at marketing our oil and natural gas at commercially acceptable prices, our profitability will decline.
Our ability to market oil and natural gas at commercially acceptable prices depends on, among other factors, the following:
•
the availability and capacity of gathering systems and pipelines;
•
federal and state regulation of production and transportation;
•
changes in supply and demand; and
•
general economic conditions.
Our inability to respond appropriately to changes in these factors could negatively affect our profitability.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and processing facilities. Our ability to market our production depends in a substantial part on the availability and capacity of gathering systems, pipelines and processing facilities, in some cases owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells for a lack of a market or because of the inadequacy or unavailability of pipelines or gathering system capacity. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver our production to market.
We depend on our key personnel and the loss of any of these individuals could have a material adverse effect on our operations.
We believe that the success of our business strategy and our ability to operate profitably depend on the continued employment of M. Jay Allison, our President and Chief Executive Officer, and a limited number of other senior management personnel. Loss of the services of Mr. Allison or any of those other individuals could have a material adverse effect on our operations.
Our insurance coverage may not be sufficient or may not be available to cover some liabilities or losses that we may incur.
If we suffer a significant accident or other loss, our insurance coverage will be net of our deductibles and may not be sufficient to pay the full current market value or current replacement value of our lost investment, which could result in a material adverse impact on our operations and financial condition. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Because third party drilling contractors are used to drill our wells, we may not realize the full benefit of workers’ compensation laws in dealing with their employees. In addition, some risks, including pollution and environmental risks, generally are not fully insurable.
We are subject to extensive governmental laws and regulations that may adversely affect the cost, manner or feasibility of doing business.
Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and natural gas, and operating safety. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with governmental laws and regulations, such as:
•
lease permit restrictions;
•
drilling bonds and other financial responsibility requirements, such as plug and abandonment bonds;
•
spacing of wells;
•
unitization and pooling of properties;
•
safety precautions;
•
regulatory requirements; and
•
taxation.
Under these laws and regulations, we could be liable for:
•
personal injuries;
•
property and natural resource damages;
•
well reclamation costs; and
•
governmental sanctions, such as fines and penalties.
Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.
Our operations may incur substantial liabilities to comply with environmental laws and regulations.
Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment and otherwise relating to environmental protection. These laws and regulations:
•
require the acquisition of one or more permits before drilling commences;
•
impose limitations on where drilling can occur and/or requires mitigation before authorizing drilling in certain locations;
•
restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;
•
require reporting of significant releases, and annual reporting of the nature and quantity of emissions, discharges and other releases into the environment;
•
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
•
impose substantial liabilities for pollution resulting from our operations.
Failure to comply with these laws and regulations may result in:
•
the assessment of administrative, civil and criminal penalties;
•
the incurrence of investigatory or remedial obligations; and
•
the imposition of injunctive relief.
In June 2009 the United States House of Representatives passed the American Clean Energy and Security Act of 2009. A similar bill, the Clean Energy Jobs and American Power Act, introduced in the Senate, did not pass. Both bills contained the basic feature of establishing a “cap and trade” system for restricting greenhouse gas emissions in the United States. Under such a system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline as necessary over time to meet overall emission reduction goals. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. It appears that the prospects for a cap and trade system such as that proposed in these bills have dimmed significantly; however, the EPA has moved ahead with its efforts to regulate GHG emissions from certain sources by rule. The EPA issued Subpart W of the Final Mandatory Reporting of Greenhouse Gases Rule, which required petroleum and natural gas systems that emit 25,000 metric tons of CO2e or more per year to begin collecting GHG emissions data under a new reporting system. We believe we have met all of the reporting requirements under these new regulations. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The EPA has adopted regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. Since all of our oil and natural gas production is in the United States, these laws or regulations that have been or may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur substantial increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.
In June 2010 the Bureau of Land Management issued a proposed oil and gas leasing reform. The proposal would require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources on federal lands, increased public engagement in the development of Master Leasing Plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process with greater public involvement in the identification of key environmental resource values before a parcel is leased. New leases would incorporate adaptive management stipulations, requiring lessees to monitor and respond to observed environmental impacts,
possibly through the implementation of expensive new control measures or curtailment of operations, potentially reducing profitability. The proposed policy could have the effect of reducing the amount of new federal lands made available for lease, increasing the competition for and cost of available parcels.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly restrictions on emissions, and/or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed. Future environmental laws and regulations, including proposed legislation regulating climate change, may negatively impact our industry. The costs of compliance with these requirements may have an adverse impact on our financial condition, results of operations and cash flows.
Provisions of our articles of incorporation, bylaws and Nevada law will make it more difficult to effect a change in control of us, which could adversely affect the price of our common stock.
Nevada corporate law and our articles of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us. These provisions include:
•
allowing for authorized but unissued shares of common and preferred stock;
•
a classified board of directors;
•
requiring special stockholder meetings to be called only by our chairman of the board, our chief executive officer, a majority of the board or the holders of at least 10% of our outstanding stock entitled to vote at a special meeting;
•
requiring removal of directors by a supermajority stockholder vote;
•
prohibiting cumulative voting in the election of directors; and
•
Nevada control share laws that may limit voting rights in shares representing a controlling interest in us.
These provisions could make an acquisition of us by means of a tender offer or proxy contest or removal of our incumbent directors more difficult. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
We are not a party to any legal proceedings which management believes will have a material adverse effect on our consolidated results of operations or financial condition.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed for trading on the New York Stock Exchange under the symbol “CRK.” The following table sets forth, on a per share basis for the periods indicated, the high and low sales prices by calendar quarter for the periods indicated as reported by the New York Stock Exchange.
As of February 28, 2013, we had 48,303,517 shares of common stock outstanding, which were held by 221 holders of record and approximately 7,900 beneficial owners who maintain their shares in “street name” accounts.
We have never paid cash dividends on our common stock. We presently intend to retain any earnings for the operation and expansion of our business and we do not anticipate paying cash dividends in the foreseeable future. Any future determination as to the payment of dividends will depend upon the results of our operations, capital requirements, our financial condition and such other factors as our board of directors may deem relevant. In addition, we are limited under our bank credit facility and by the terms of the indentures for our senior notes from paying or declaring cash dividends.
During the fourth quarter of 2012, we did not repurchase any of our equity securities.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The historical financial data presented in the table below as of and for each of the years in the five-year period ended December 31, 2012 are derived from our consolidated financial statements. The financial results are not necessarily indicative of our future operations or future financial results. The data presented below should be read in conjunction with our consolidated financial statements and the notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” In 2008, we divested our interests in offshore operations which were conducted through our subsidiary Bois d’Arc Energy, Inc. (“Bois d’Arc”). Accordingly, we have adjusted the presentation of selected financial data to reflect the offshore operations on a discontinued basis.
Statement of Operations Data:
(1) Includes ad valorem taxes.
(2) Includes gain of $158.1 million, net of income taxes of $85.3 million, from the sale of our offshore operations.
(3) Basic and diluted weighted average shares are the same due to the net loss.
Balance Sheet Data:
Cash Flow Data:
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our selected historical consolidated financial data and our accompanying consolidated financial statements and the notes to those financial statements included elsewhere in this report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”
Overview
We are an independent energy company engaged in the acquisition, exploration, development and production of oil and natural gas in the United States. We own interests in 1,643 producing oil and natural gas wells (914.5 net to us) and we operate 962 of these wells. In managing our business, we are concerned primarily with maximizing return on our stockholders’ equity. To accomplish this goal, we focus on profitably increasing our oil and natural gas reserves and production.
Our future growth will be driven primarily by acquisition, development and exploration activities. In 2012 our growth in production and proved reserves was primarily driven by our successful oil focused drilling activities. Under our current drilling budget, we plan to spend approximately $420.0 million in 2013 for development and exploration activities, which will primarily be focused on oil projects. We plan to drill 85 wells (58.1 net to us) in 2013, of which 75 wells (54.5 net to us) will target oil in our South Texas and West Texas regions and ten will target natural gas in our East Texas / North Louisiana region. However, we could increase or decrease the number of wells that we drill depending on oil and natural gas prices. We do not specifically budget for acquisitions as the timing and size of acquisitions are not predictable.
We use the successful efforts method of accounting, which allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration activities. Accordingly, our exploration costs consist of costs we incur to acquire and reprocess 3-D seismic data, impairments of our unevaluated leasehold where we were not successful in discovering reserves and the costs of unsuccessful exploratory wells that we drill.
We generally sell our oil and natural gas at current market prices at the point our wells connect to third party purchaser pipelines. We have entered into certain transportation and treating agreements with midstream and pipeline companies to transport a substantial portion of our natural gas production in North Louisiana to long-haul gas pipelines. We market our products several different ways depending upon a number of factors, including the availability of purchasers for the product, the availability and cost of pipelines near our wells, market prices, pipeline constraints and operational flexibility. Accordingly, our revenues are heavily dependent upon the prices of, and demand for, oil and natural gas. Oil and natural gas prices have historically been volatile and are likely to remain volatile in the future.
Our operating costs are generally comprised of several components, including costs of field personnel, insurance, repair and maintenance costs, production supplies, fuel used in operations, transportation costs, workover expenses and state production and ad valorem taxes.
Like all oil and natural gas exploration and production companies, we face the constant challenge of replacing our reserves. Although in the past we have offset the effect of declining production rates from existing properties through successful acquisition and drilling efforts, there can be no assurance that we will be able to continue to offset production declines or maintain production at current rates through future acquisitions or drilling activity. Our future growth will depend on our ability to continue to add new reserves in excess of production.
Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and natural gas, and operating safety. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may have an adverse effect on our business, results of operations and financial condition. Applicable environmental regulations require us to remove our equipment after production has ceased, to plug and abandon our wells and to remediate any environmental damage our operations may have caused. The present value of the estimated future costs to plug and abandon our oil and gas wells and to dismantle and remove our production facilities is included in our reserve for future abandonment costs, which was $18.0 million as of December 31, 2012.
Results of Operations
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Our operating data for 2011 and 2012 is summarized below:
(1) Includes realized gains from derivatives of $9.8 million in 2012.
(2) Includes ad valorem taxes.
(3) Represents depreciation, depletion and amortization of oil and gas properties only.
Oil and gas sales. Our oil and gas sales decreased $2.5 million (1%) in 2012 to $431.9 million from sales of $434.4 million in 2011. Our oil production in 2012 increased by 175% while our natural gas production decreased by 9% from our 2011 production levels. On an equivalent unit basis, our production in 2012 increased by 1% over 2011. Our successful drilling program grew our oil production which offset the decline in natural gas production. Prices realized for oil sales increased by 1% in 2012 as compared to 2011 while the average price we realized for natural gas sales decreased by 36% in 2012 as compared to 2011. Our oil hedging program generated $9.8 million in realized gains in 2012. Including the results of our hedging program, our average oil price in 2012 of $101.18 increased 6% above last year’s average price.
Production taxes. Production taxes increased $10.3 million or 282% to $14.0 million in 2012 from $3.7 million in 2011. The increase in 2012 is due to the significant growth in our oil sales during the year. Much of our natural gas sales in 2011 and 2012 qualify for exemption from state production taxes.
Gathering and transportation. Gathering and transportation costs in 2012 decreased $1.2 million (4%) to $27.3 million as compared to $28.5 million in 2011 due to the lower natural gas volumes that we produced in North Louisiana in 2012.
Lease operating expenses. Our lease operating expenses, including ad valorem taxes, of $60.6 million in 2012 were $14.0 million or 30% higher than our operating expenses of $46.6 million in 2011. Our lease operating expense per Mcfe produced increased by 29% to $1.06 per Mcfe in 2012 as compared to $0.82 per Mcfe in 2011. The increase mainly reflects our growing oil production. Our oil wells are typically more costly to operate than our natural gas wells. Oil production comprised 14% of our total production in 2012 as compared to 5% in 2011.
Exploration expense. We incurred $61.4 million in exploration expense in 2012 as compared to $10.1 million in 2011. Exploration expense in 2012 consisted of $61.3 million of impairments of
unevaluated leasehold costs and $0.1 million for the acquisition of seismic data. Our 2011 exploration cost consisted of $9.8 million of impairments of unevaluated leasehold costs and $0.3 million for the acquisition of seismic data.
Depreciation, depletion and amortization expense (“DD&A”). DD&A of $365.3 million was an increase of $74.5 million (26%) over DD&A of $290.8 million in 2011. Our DD&A rate per Mcfe produced averaged $3.83 in 2012 as compared to $3.00 for 2011. The increase in DD&A primarily resulted from increased development costs per Mcfe associated with the oil wells drilled in 2012, and the substantial decline in our proved natural gas reserves due to the low natural gas prices in 2012.
Impairment of oil and gas properties. We recorded impairments to our oil and gas properties of $25.4 million and $60.8 million in 2012 and 2011, respectively. These impairments relate to fields where an impairment was indicated based on estimated future cash flows from the properties.
General and administrative expenses. General and administrative expense of $33.8 million for 2012 was 4% lower than general and administrative expense of $35.2 million for 2011. The decrease primarily reflects lower stock based compensation in 2012. Stock based compensation decreased by $1.3 million to $13.7 million in 2012 as compared to $15.0 million in 2011.
Interest expense. Interest expense increased $21.9 million (51%) to $64.6 million in 2012 from interest expense of $42.7 million in 2011. The increase was primarily related to the increase in outstanding debt during 2012 including the issuance of $300.0 million in senior notes in June 2012. Average borrowings under our bank credit facility increased to $482.7 million in 2012 as compared to $121.4 million for 2011. The average interest rate on the outstanding borrowings under our credit facility of 3.0% in 2012 was higher than the interest rate of 2.2% in 2011. We capitalized interest of $20.9 million and $13.2 million in 2012 and 2011, respectively, which amounts reduced interest expense.
Income taxes. The benefit from income taxes increased in 2012 to $47.4 million from $14.6 million in 2011 due to the higher net loss in 2012. Our effective tax rate of 32% in 2012 and 30% in 2011 differed from the federal income tax rate of 35% primarily due to the effect of nondeductible compensation and state income taxes.
Net loss. We reported a loss of $100.1 million for 2012 as compared to a loss of $33.5 million for 2011. The loss per share for 2012 was $2.16 on weighted average shares outstanding of 46.4 million as compared to a loss per share of $0.73 for 2011 on weighted average shares outstanding of 46.0 million. The loss in 2012 was primarily related to the increase in DD&A expense and impairments of proved and unproved properties of $86.7 million ($56.3 million after income taxes) which were offset in part by gains on sales of properties of $24.3 million ($15.8 million after income taxes) and sales of marketable securities of $26.6 million ($17.3 million after income taxes) and also unrealized gains on our oil derivatives of $11.5 million ($7.5 million after tax). The loss in 2011 was primarily related to the impairments to proved and unproved properties in 2011 of $70.6 million ($45.9 million after income taxes) offset in part by gains on sales of marketable securities of $35.1 million ($22.8 million after income taxes).
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
Our operating data for 2010 and 2011 is summarized below:
(1) Includes ad valorem taxes.
(2) Represents depreciation, depletion and amortization of oil and gas properties only.
Oil and gas sales. Our oil and gas sales increased $85.3 million (24%) in 2011 to $434.4 million from sales of $349.1 million in 2010. This increase resulted from higher natural gas production and higher prices realized for oil sales in 2011. Our production in 2011 increased by 31% over 2010’s production as production from new wells drilled in South Texas targeting the Eagle Ford shale and in North Louisiana targeting the Haynesville/Bossier shales exceeded declines from our existing producing properties. Prices realized for oil sales increased by 40% in 2011 as compared to 2010 while the average price we realized for natural gas sales decreased by 10% in 2011 as compared to 2010. During 2011 we drilled 87 wells (47.7 net to us), 62 of which were Haynesville or Bossier shale horizontal wells and 20 of which were Eagle Ford shale horizontal wells. At December 31, 2011 we had 23 wells (15.5 net to us) that were drilled in 2011 awaiting completion.
Production taxes. Production taxes decreased $6.2 million (63%) to $3.7 million in 2011 from $9.9 million in 2010. Our Haynesville and Bossier shale wells, which comprise a large percentage of our production, qualify for exemption from certain state production taxes. The exempt wells together with the lower natural gas prices account for the decrease.
Gathering and transportation. Gathering and transportation costs in 2011 increased $11.2 million (65%) to $28.5 million as compared to $17.3 million in 2010 due to the transportation costs related to the higher production from our Haynesville/Bossier shale properties in North Louisiana.
Lease operating expenses. Our lease operating expenses, including ad valorem taxes, of $46.6 million in 2011 were $6.9 million or 13% lower than our operating expenses of $53.5 million in 2010. Our lease operating expense per Mcfe produced decreased by 33% to $0.48 per Mcfe in 2011 as compared to $0.72 per Mcfe in 2010. The decreases in lease operating expenses are primarily due to the sale of our higher operating cost properties in Mississippi in 2010.
Exploration expense. We incurred $10.1 million in exploration expense in 2011 as compared to $2.6 million in 2010. Exploration expense in 2011 consisted of $9.8 million of impairments of unevaluated leasehold costs and $0.3 million for the acquisition of seismic data. Our 2010 exploration cost primarily related to costs incurred for the acquisition of seismic data.
DD&A. DD&A of $290.8 million increased $77.0 million (36%) as compared to DD&A of $213.8 million in 2010. Our DD&A rate per Mcfe produced averaged $3.00 in 2011 as compared to $2.91 for 2010. The increase in DD&A primarily resulted from our 31% growth in production in 2011.
Impairment of oil and gas properties. We recorded impairments to our oil and gas properties of $60.8 million and $0.2 million in 2011 and 2010, respectively. These impairments relate to fields where an impairment was indicated based on estimated future cash flows from the properties. The 2011 impairment is a result of lower anticipated natural gas prices.
General and administrative expenses. General and administrative expense of $35.2 million for 2011 was 5% lower than general and administrative expense of $37.2 million for 2010. The decrease primarily reflects our lower personnel costs in 2011. Stock based compensation decreased by $2.4 million to $15.0 million in 2011 as compared to $17.4 million in 2010.
Interest expense. Interest expense increased $13.2 million (45%) to $42.7 million in 2011 from interest expense of $29.5 million in 2010. The increase was primarily related to the increase in outstanding debt during 2011 including the issuance of $300.0 million in senior notes in March 2011. Average borrowings under our bank credit facility increased to $121.4 million in 2011 as compared to $70.0 million for 2010. The average interest rate on the outstanding borrowings under our credit facility of 2.2% in 2011 was unchanged from 2010. We capitalized interest of $13.2 million and $13.0 million in 2011 and 2010, respectively, which reduced interest expense. Interest expense in 2011 includes $1.1 million for the early retirement of our 6 7/8% senior notes which were due in March 2012.
Income taxes. The benefit from income taxes increased in 2011 to $14.6 million from $4.8 million in 2010 due to the higher net loss in 2011. Our effective tax rate of 30% in 2011 and 20% in 2010 differed from the federal income tax rate of 35% primarily due to the effect of nondeductible compensation and state income taxes.
Net loss. We reported a loss of $33.5 million for 2011 as compared to a loss of $19.6 million for 2010. The loss per share for 2011 was $0.73 on weighted average shares outstanding of 46.0 million as compared to a loss per share of $0.43 for 2010 on weighted average shares outstanding of 45.6 million. The loss in 2011 was primarily related to the impairments to proved and unproved properties in 2011 of $70.6 million ($45.9 million after income taxes) offset in part by gains on sales of marketable securities of $35.1 million ($22.8 million after income taxes). The loss in 2010 was primarily related to the loss on our divestiture of oil and gas properties in Mississippi of $25.8 million ($16.8 million after income taxes).
Liquidity and Capital Resources
Funding for our activities has historically been provided by our operating cash flow, debt or equity financings and asset dispositions. Our net cash provided by operating activities in 2012 totaled $262.2 million. Our other primary sources of funds in 2012 included $285.9 million of net proceeds from a senior notes offering and $204.4 million from sales of assets. In 2011, our net cash flow provided by operating activities totaled $284.9 million, while our other primary sources of funds included $293.4 million of net proceeds from a senior notes offering, $555.0 million of borrowings under our bank credit facility and $53.4 million of proceeds from sales of marketable securities. In 2010, our net cash flow provided by operating activities from continuing operations totaled $311.7 million. Our other primary source of funds in 2010 was $96.9 million of net proceeds from sales of oil and gas properties and marketable securities and $45.0 million of borrowings under our bank credit facility.
Our cash flow from operating activities in 2012 of $262.2 million represented a decrease of $22.7 million from our cash from operating activities of $284.9 million in 2011. Cash flow from
operations excluding changes in working capital accounts of $261.3 million in 2012 decreased by $36.3 million or 12% as compared to $297.6 million in 2011 due to the lower revenues we received because of the decline in natural gas prices during 2012 which was partially offset by higher oil production. Our cash flow from operating activities in 2011 decreased by $26.8 million to $284.9 million as compared to $311.7 million in 2010 primarily due to changes in working capital at the end of 2011.
Our primary need for capital, in addition to funding our ongoing operations, relates to the acquisition, development and exploration of our oil and gas properties and the repayment of our debt. During 2012 our capital expenditures of $550.6 million decreased by $497.1 million as compared to 2011 capital expenditures of $1.0 billion due primarily to the acquisitions of proved and unproved properties we made in 2011. Capital expenditures in 2012 include $70.9 million spent to complete wells drilled in 2011. In 2011, our capital expenditures of $1.0 billion increased by $502.0 million as compared to 2010 capital expenditures of $545.7 million, mainly due to the acquisition of oil and gas properties in 2011.
Our annual capital expenditure activity is summarized in the following table:
(1) Excludes reimbursements from joint venture partner for preformation well costs of $23.8 million.
The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments except for contracted drilling and completion services. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. We currently expect to spend approximately $445.0 million for development and exploration projects and lease acquisitions in 2013, which will be funded primarily by cash flows from operating activities, proceeds from asset sales and borrowings under our credit facility. Our operating cash flow and, therefore, our capital expenditures are highly dependent on oil and natural gas prices and, in particular, natural gas prices.
We do not have a specific acquisition budget for 2013 because the timing and size of acquisitions are unpredictable. Smaller acquisitions will generally be funded from operating cash flow. With respect to significant acquisitions, we intend to use borrowings under our bank credit facility, or other debt or equity financings to the extent available, to finance such acquisitions. The availability and attractiveness of these sources of financing will depend upon a number of factors, some of which will relate to our financial condition and performance and some of which will be beyond our control, such as prevailing interest rates, oil and natural gas prices and other market conditions. Lack of access to the debt or equity markets due to general economic conditions could impede our ability to complete acquisitions.
We have a $850.0 million bank credit facility with Bank of Montreal, as the administrative agent. The bank credit facility is a five-year revolving credit commitment that matures on November 30, 2015.
Indebtedness under the bank credit facility is secured by all of our and our wholly owned subsidiaries’ assets and is guaranteed by all of our wholly owned subsidiaries. The bank credit facility is subject to borrowing base availability, which is redetermined semiannually based on the banks’ estimates of the future net cash flows of our oil and natural gas properties. As of December 31, 2012, the borrowing base was $570.0 million, $130.0 million of which was available. The borrowing base may be affected by the performance of our properties and changes in oil and natural gas prices. The determination of the borrowing base is at the sole discretion of the administrative agent and the bank group. Borrowings under the bank credit facility bear interest, based on the utilization of the borrowing base, at our option at either (1) LIBOR plus 1.75% to 2.75% or (2) the base rate (which is the higher of the administrative agent’s prime rate, the federal funds rate plus 0.5% or 30 day LIBOR plus 1.0%) plus 0.75% to 1.75%. A commitment fee of 0.5% is payable on the unused borrowing base. The bank credit facility contains covenants that, among other things, restrict the payment of cash dividends in excess of $50.0 million, limit the amount of consolidated debt that we may incur and limit our ability to make certain loans and investments. The only financial covenants are the maintenance of a ratio of current assets, including the availability under the bank credit facility, to current liabilities and maintenance of a leverage ratio. We were in compliance with these covenants as of December 31, 2012.
We have $300.0 million of 8 3/8% senior notes outstanding which are due October 15, 2017, $300.0 million of 7 3/4% senior notes outstanding which are due April 1, 2019 and $300.0 million of 9 1/2% senior notes outstanding which are due June 15, 2020. All senior notes have semi-annual interest payment obligations, are unsecured obligations and are guaranteed by all of our material subsidiaries.
On January 1, 2011, we had $172.0 million in principal amount of 6 7/8% senior notes outstanding due in 2012 (the “2012 Notes”). We redeemed all of the 2012 Notes in 2011 for $172.4 million. The early extinguishment of the 2012 Notes resulted in a loss of $1.1 million. This loss is comprised of the premium paid for the redemption of the 2012 Notes, the costs incurred related to the tender offer, and the write-off of unamortized debt issuance costs related to the 2012 Notes.
We believe that our cash flow from operations and available borrowings under our bank credit facility will be sufficient to fund our operations and future growth as contemplated under our current business plan. However, if our plans or assumptions change or if our assumptions prove to be inaccurate, we may be required to seek additional capital. We cannot provide any assurance that we will be able to obtain such capital, or if such capital is available, that we will be able to obtain it on acceptable terms.
The following table summarizes our aggregate liabilities and commitments by year of maturity:
Future interest costs are based upon the effective interest rates of our outstanding senior notes and the December 31, 2012 rate for our bank credit facility.
We have obligations to incur future payments for dismantlement, abandonment and restoration costs of oil and gas properties. These payments are currently estimated to be incurred primarily after 2017. We record a separate liability for the fair value of these asset retirement obligations, which totaled $18.0 million as of December 31, 2012.
Federal Taxation
At December 31, 2012 we had U.S. federal net operating loss carryforwards of approximately $192.3 million and Louisiana state net operating loss carryforwards of approximately $536.4 million. Utilization of $36.9 million of our U.S. federal net operating loss carryforwards is limited to approximately $1.1 million per year pursuant to a prior change of control of an acquired company and a valuation allowance of $23.0 million has been established for the estimated U.S. federal net operating loss carryforwards that will not be utilized. Realization of the remaining U.S. federal net operating loss carryforwards requires Comstock to generate taxable income within the carryforward period. A valuation allowance of $288.0 million has been established against our Louisiana state net operating loss carryforwards due to the uncertainty of generating taxable income in the state of Louisiana prior to the expiration of the carryforward period.
Our federal income tax returns for the years subsequent to December 31, 2007 remain subject to examination. Our income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2007. We currently believe that our significant filing positions are highly certain and that all of our significant income tax filing positions and deductions would be sustained upon audit or the final resolution would not have a material effect on our consolidated financial statements. Therefore, we have not established any significant reserves for uncertain tax positions. Interest and penalties resulting from audits by tax authorities have been immaterial and are included in the provision for income taxes in the consolidated statements of operations.
Critical Accounting Policies
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and use assumptions that can affect the reported amounts of assets, liabilities, revenues or expenses.
Successful efforts accounting. We are required to select among alternative acceptable accounting policies. There are two generally acceptable methods for accounting for oil and gas producing activities. The full cost method allows the capitalization of all costs associated with finding oil and natural gas reserves, including certain general and administrative expenses. The successful efforts method allows only for the capitalization of costs associated with developing proven oil and natural gas properties as well as exploration costs associated with successful exploration projects. Costs related to exploration that are not successful are expensed when it is determined that commercially productive oil and gas reserves were not found. We have elected to use the successful efforts method to account for our oil and gas activities and we do not capitalize any of our general and administrative expenses.
Oil and natural gas reserve quantities. The determination of depreciation, depletion and amortization expense is highly dependent on the estimates of the proved oil and natural gas reserves attributable to our properties. The determination of whether impairments should be recognized on our oil and gas properties is also dependent on these estimates, as well as estimates of probable reserves. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate depends on the quality of available data, production history and engineering and geological interpretation and judgment. Because all reserve
estimates are to some degree imprecise, the quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas prices may all differ materially from those assumed in these estimates. The information regarding present value of the future net cash flows attributable to our proved oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Any future downward revisions could adversely affect our financial condition, our borrowing ability, our future prospects and the value of our common stock.
Impairment of oil and gas properties. We evaluate our properties on a field area basis for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable. If impairment is indicated based on a comparison of the asset’s carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Expected future cash flows are determined using estimated future prices based on market based forward prices applied to projected future production volumes. The projected production volumes are based on the property’s proved and risk adjusted probable oil and natural gas reserve estimates at the end of the period. The estimated future cash flows that we use in our assessment of the need for an impairment are based on market prices for oil and natural gas for the next three years, with a 5% escalation of prices for subsequent years. Prices are not escalated to levels that exceed observed historical market prices. Costs are also assumed to escalate at a rate that is based on our historical experience, currently estimated at 2% per annum. The oil and natural gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of the average first day of the month historical price for the year. To the extent that oil and natural gas prices do not increase as anticipated in these assumptions or costs increase at a greater rate than assumed, certain of our evaluated properties which presently have a carrying value of $463.0 million may require impairment in the future. The amount of such impairments would be based on the write down of these properties to their then current estimated fair value. In addition to these properties, other properties may become impaired due to downward revisions in reserve or price estimates or for other reasons.
Asset retirement obligations. We have obligations to remove tangible equipment and facilities and to restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of any surface equipment used in production operations. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
Stock-based compensation. We follow the fair value based method in accounting for equity-based compensation. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period.
Related Party Transactions
In recent years, we have not entered into any material transactions with our officers or directors apart from the compensation they are provided for their services. We also have not entered into any business transactions with our significant stockholders or any other related parties.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Oil and Natural Gas Prices
Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil, the foreign supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse affect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on our oil and natural gas production in 2012, a $1.00 change in the price per barrel of oil would have resulted in a change in our cash flow for such period by approximately $0.6 million and a $0.10 change in the price per Mcf of natural gas would have changed our cash flow by approximately $8.0 million.
We have entered into oil price swap agreements covering 2.2 million barrels of our expected 2013 oil production which fix the NYMEX West Texas Intermediate (“WTI”) price at $98.67 per barrel. As of December 31, 2012, our outstanding oil swap agreements had a fair value of $11.7 million. The change in the fair value of our oil swaps that would result from a 10% change in commodities prices at December 31, 2012 would be $12.9 million. Such a change in fair value could be a gain or a loss depending on whether prices increase or decrease.
Interest Rates
At December 31, 2012, we had $1.3 billion of long-term debt. Of this amount, $300.0 million bears interest at 8 3/8%, $300.0 million bears interest at a fixed rate of 7 3/4%, and $300.0 million bears interest at 9 1/2%. The fair market value of our fixed rate debt as of December 31, 2012 was $942.0 million based on the market price of approximately 107% of the face amount. At December 31, 2012, we had $440.0 million outstanding under our bank credit facility, which is subject to variable rates of interest. Borrowings under the bank credit facility bear interest at a fluctuating rate that is tied to LIBOR or the corporate base rate, at our option. Any increase in these interest rates would have an adverse impact on our results of operations and cash flow. Based on borrowings outstanding at December 31, 2012, a 100 basis point change in interest rates would change our annual interest expense on our variable rate debt by approximately $4.4 million. We had no interest rate derivatives outstanding during 2012 or at December 31, 2012.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our consolidated financial statements are included on pages to of this report.
We have prepared these financial statements in conformity with generally accepted accounting principles. We are responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the preparation of the financial statements, it is necessary for us to make informed estimates and judgments based on currently available information on the effects of certain events and transactions.
Our independent public accountants, Ernst & Young LLP, are engaged to audit our financial statements and to express an opinion thereon. Their audit is conducted in accordance with auditing standards generally accepted in the United States to enable them to report whether the financial statements present fairly, in all material respects, our financial position and results of operations in accordance with accounting principles generally accepted in the United States.
The audit committee of our board of directors is comprised of three directors who are not our employees. This committee meets periodically with our independent public accountants and management. Our independent public accountants have full and free access to the audit committee to meet, with and without management being present, to discuss the results of their audits and the quality of our financial reporting.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Controls and Procedures. Disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act) are designed to provide reasonable assurance that information required to be disclosed in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.
We performed an evaluation of the effectiveness of our disclosure controls and procedures as of December 31, 2012. The evaluation was performed with the participation of senior management of each business segment and key corporate functions, and under the supervision of the Chief Executive Officer and Chief Financial Officer. As described below, management has identified a material weakness in our internal control over financial reporting, which is an integral component of our disclosure controls and procedures. As a result of this material weakness, we concluded that our disclosure controls and procedures were not effective as of December 31, 2012.
As part of the preparation of our financial statements for the year ended December 31, 2012, we undertook a review of our accounting for oil price derivative financial instruments. We use derivative financial instruments as a means of reducing our exposure to fluctuating commodity prices for oil and natural gas. During the quarters ended March 31, 2012, June 30, 2012 and September 30, 2012, we applied cash flow hedge accounting for our derivative financial instruments as provided for in Accounting Standards Codification Topic 815, Derivatives and Hedging (“ASC 815”). Accordingly, we included changes from period to period in the fair value of derivative financial instruments classified as cash flow hedges as increases or decreases to Accumulated Other Comprehensive Income (“AOCI”). In order to qualify for cash flow hedge accounting treatment, specific standards and contemporaneous documentation requirements must be met. We believed that we had met those requirements and that our hedge accounting treatment was permitted under ASC 815. However, in connection with preparing our 2012 Annual Report, and based upon discussions with Ernst & Young, LLP, our independent public accounting firm, we determined that our hedge documentation was not completed in a timely manner, and as a result our commodity derivative financial instruments did not qualify for hedge accounting treatment under ASC 815.
In February 2013 the Audit Committee of our Board of Directors concluded that our previously issued consolidated financial statements contained a material error with respect to accounting for derivative financial instruments, and should be restated. Accordingly, we are restating the consolidated financial statements for each of the three months ended March 31, 2012, June 30, 2012 and September 30, 2012 to reflect the change in the fair value of our derivative financial instruments, as a separate component of other income (expenses) in our statements of operations rather than as a component of AOCI. We are also reclassifying the realized gains and losses from our derivative financial instruments as a component of other income (expenses) rather than as a component of oil and gas sales.
We have concluded, based on the circumstances involving the restatement of the financial statements for the three months ended March 31, 2012, June 30, 2012 and September 30, 2012, that a material weakness in internal control over financial reporting existed at December 31, 2012 with respect to the design of our controls over the timeliness of documentation required to designate our derivative financial instruments as cash flow hedges in accordance with ASC 815.
Management’s Report on Internal Control over Financial Reporting. We are responsible for establishing and maintaining adequate internal control over financial reporting for the company. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act, we conducted an assessment, including testing, using the criteria in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Our system of internal control over financial reporting is designed 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. 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.
A “material weakness” is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness relating to the accounting for derivative financial instruments resulted in misstatements of the aforementioned accounts and disclosures that resulted in material misstatements in our interim financial statements. Because of this material weakness, management has concluded that we did not maintain effective internal control over financial reporting as of December 31, 2012. Our internal control over financial reporting as of December 31, 2012, has been audited by Ernst & Young, LLP, an independent registered public accounting firm, as stated in their report included herein.
Plans for Remediation of the Material Weakness. In response to the material weakness, we did not account for derivative financial instruments as cash flow hedges under ASC 815 in the fourth quarter of 2012 and are recognizing realized gains and losses and changes in the fair value of our derivative financial instruments in current earnings as separate components of other income (losses). We are developing a remediation plan to address the material weakness described above. The remediation plan will include designing and implementing a control framework over entering into derivative financial instruments to ensure that our accounting for derivative financial instruments which was affected by the material control weakness is appropriate. The remediation plan will involve key leaders from across the organization, including the Chief Executive Officer, the Chief Financial Officer and our internal auditors. We will report quarterly and as needed to the Audit Committee of our Board of Directors on the progress made toward completion of the remediation plan.
We continue to monitor the effectiveness of our internal control over financial reporting with respect to our accounting for derivatives which was affected by the material weakness described above. We will
perform additional procedures prescribed by management, including the use of manual mitigating control procedures, and we will employ any additional tools and resources deemed necessary to ensure that our financial statements continue to be fairly stated in all material respects.
Changes in Internal Control over Financial Reporting. Except as noted above with respect to our discontinuation of cash flow hedge accounting in the fourth quarter of 2012, there were no changes in our internal control over financial reporting during the quarter ended December 31, 2012 that materially affected or are reasonably likely to materially affect our internal control over financial reporting. However, as described above under “Plans for Remediation of Material Weaknesses,” we have initiated a process to improve the control environment and to remedy the control weakness described herein.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Comstock Resources, Inc.
We have audited Comstock Resources, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Comstock Resources, Inc. and subsidiaries’ management is responsible 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 the company’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit 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, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed 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 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.
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment. Management has identified a material weakness in controls related to the Company’s accounting for derivative financial instruments at December 31, 2012. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Comstock Resources, Inc. and subsidiaries as of December 31, 2011 and 2012, and the related consolidated statements of operations, comprehensive loss, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2012. This material weakness was considered in determining the nature, timing and extent of audit tests applied in our audit of the 2012 financial statements and this report does not affect our report dated February 28, 2013, which expressed an unqualified opinion on those financial statements.
In our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Comstock Resources, Inc. and subsidiaries have not maintained effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.
Dallas, Texas
February 28, 2013
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item is incorporated herein by reference to “Business - Directors and Executive Officers” in this Form 10-K and to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2012.
Code of Ethics. We have adopted a Code of Business Conduct and Ethics that is applicable to all of our directors, officers and employees as required by New York Stock Exchange rules. We have also adopted a Code of Ethics for Senior Financial Officers that is applicable to our Chief Executive Officer and Senior Financial Officers. Both the Code of Business Conduct and Ethics and Code of Ethics for Senior Financial Officers may be found on our website at www.comstockresources.com. Both of these documents are also available, without charge, to any stockholder upon request to: Comstock Resources, Inc., Attn: Investor Relations, 5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034, (972) 668-8800. We intend to disclose any amendments or waivers to these codes that apply to our Chief Executive Officer and senior financial officers on our website in accordance with applicable SEC rules. Please see the definitive proxy statement for our 2013 annual meeting, which will be filed with the SEC within 120 days of December 31, 2012, for additional information regarding our corporate governance policies.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2012.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The following table summarizes certain information regarding our equity compensation plans as of December 31, 2012:
Number of securities to be
issued upon exercise of
outstanding options, warrants
and rights
Weighted average exercise
price of outstanding options,
warrants and rights
Number of securities authorized
for future issuance under
equity compensation plans
(excluding outstanding
options, warrants and rights)
Equity compensation plans approved by stockholders
845,695(1)
$38.36(2)
1,607,372
(1) Includes performance share unit awards equivalent to 688,545 shares that would be issuable based upon achievement of the maximum awards under the terms of the performance share unit awards.
(2) Price reflects the grant date fair value of 157,150 stock options that are outstanding; excludes performance share units for which the price cannot be determined until the performance targets are met.
We do not have any equity compensation plans that were not approved by stockholders.
Further information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2012.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTORS INDEPENDENCE
The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2012.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2012.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Financial Statements:
1. The following consolidated financial statements and notes of Comstock Resources, Inc. are included on Pages to of this report:
2. All financial statement schedules are omitted because they are not applicable, or are immaterial or the required information is presented in the consolidated financial statements or the related notes.
(b) Exhibits:
The exhibits to this report required to be filed pursuant to Item 15 (c) are listed below.
* Filed herewith.
+ Furnished herewith.
# Management contract or compensatory plan document.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
COMSTOCK RESOURCES, INC.
By:
/s/ M. JAY ALLISON
M. Jay Allison
President and Chief Executive Officer
(Principal Executive Officer)
Date: February 28, 2013
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
FINANCIAL STATEMENTS
INDEX
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Comstock Resources, Inc.
We have audited the accompanying consolidated balance sheets of Comstock Resources, Inc. and subsidiaries as of December 31, 2011 and 2012, and the related consolidated statements of operations, comprehensive loss, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Comstock Resources, Inc. and subsidiaries at December 31, 2011 and 2012, and the consolidated results of their operations and cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Comstock Resources, Inc.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2013 expressed an adverse opinion thereon.
/s/ ERNST & YOUNG LLP
Dallas, Texas
February 28, 2013
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31, 2011 and 2012
The accompanying notes are an integral part of these statements.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended December 31, 2010, 2011 and 2012
The accompanying notes are an integral part of these statements.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
For the Years Ended December 31, 2010, 2011 and 2012
The accompanying notes are an integral part of these statements.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
For the Years Ended December 31, 2010, 2011 and 2012
The accompanying notes are an integral part of these statements.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2010, 2011 and 2012
The accompanying notes are an integral part of these statements.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies
Accounting policies used by Comstock Resources, Inc. reflect oil and natural gas industry practices and conform to accounting principles generally accepted in the United States of America.
Basis of Presentation and Principles of Consolidation
Comstock Resources, Inc. is engaged in oil and natural gas exploration, development and production, and the acquisition of producing oil and natural gas properties. The Company’s operations are primarily focused in Texas and Louisiana. The consolidated financial statements include the accounts of Comstock Resources, Inc. and its wholly owned or controlled subsidiaries (collectively, “Comstock” or the “Company”). During 2011 and 2012 the consolidated financial statements also include the accounts of a variable interest entity where the Company was the primary beneficiary of the arrangements. All significant intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its undivided interest in oil and gas properties using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are included in its financial statements.
Reclassifications
Certain reclassifications have been made to prior periods’ financial statements to conform to the current presentation.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with generally accepted accounting principles 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 financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from those estimates. Changes in the future estimated oil and natural gas reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analysis could have a significant impact on the future results of operations.
Concentration of Credit Risk and Accounts Receivable
Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative financial instruments. The Company places its cash with high credit quality financial institutions and its derivative financial instruments with financial institutions and other firms that management believes have high credit ratings. Substantially all of the Company’s accounts receivable are due from either purchasers of oil and gas or participants in oil and gas wells for which the Company serves as the operator. Generally, operators of oil and gas wells have the right to offset future revenues against unpaid charges related to operated wells. Oil and gas sales are generally unsecured. The Company’s policy is to assess the collectability of its receivables based upon their age, the credit quality of the purchaser or participant and the potential for revenue offset. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectible. Accordingly, no allowance for doubtful accounts has been provided.
Marketable Securities
As of December 31, 2011 and 2012, the Company owned 1,806,000 and 600,000 shares, respectively, of Stone Energy Corporation common stock which was reflected in the consolidated balance sheets as marketable securities. As of December 31, 2011 and 2012, the cost basis of the marketable
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
securities was $16.6 million and $5.5 million, respectively. As of December 31, 2011 and 2012, the estimated fair value of the marketable securities was $47.6 million and $12.3 million, respectively, after recognizing unrealized gain after income taxes of $20.2 million and $4.4 million, respectively. The Company does not exert influence over the operating and financial policies of Stone, and has classified its investment in these shares as an available-for-sale security in the consolidated balance sheets. Available-for-sale securities are accounted for at fair value, with any unrealized gains and unrealized losses not determined to be other than temporary reported in the consolidated balance sheet within accumulated other comprehensive income as a separate component of stockholders’ equity. The Company utilizes the specific identification method to determine the cost of any securities sold. During 2010, 2011 and 2012 the Company sold 1,520,000, 1,991,000 and 1,206,000 shares of Stone common stock for proceeds of $30.5 million, $53.4 million and $37.7 million, respectively. Comstock realized gains before income taxes of $16.5 million, $35.1 million and $26.6 million on these sales during 2010, 2011 and 2012, respectively. The Company reviews its available-for-sale securities to determine whether a decline in fair value below the respective cost basis is other than temporary. Unrealized losses are charged against net earnings when a decline in fair value is determined to be other than temporary.
Other Current Assets
Other current assets at December 31, 2011 and 2012 consist of the following:
Fair Value Measurements
The Company holds or has held certain items that are required to be measured at fair value. These include cash equivalents held in bank accounts, marketable securities and derivative financial instruments in the form of oil price swap agreements. Fair value is defined as the price that would be received to sell 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. A three-level hierarchy is followed for disclosure to show the extent and level of judgment used to estimate fair value measurements:
Level 1 - Inputs used to measure fair value are unadjusted quoted prices that are available in active markets for the identical assets or liabilities as of the reporting date.
Level 2 - Inputs used to measure fair value, other than quoted prices included in Level 1, are either directly or indirectly observable as of the reporting date through correlation with market data,
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument.
Level 3 - Inputs used to measure fair value are unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management’s estimates of market participant assumptions.
The Company’s cash and marketable securities valuation are based on Level 1 measurements. The Company’s oil and natural gas price swap agreements were not traded on a public exchange, and their value was determined utilizing a discounted cash flow model based on inputs that are readily available in public markets and, accordingly, the valuation of these swap agreements was categorized as a Level 2 measurement.
The following table summarizes financial assets accounted for at fair value as of December 31, 2012:
As of December 31, 2012 the Company had oil price swap agreements for 2,160,000 barrels of oil to be produced in 2013 with a fair value of $11.7 million. The Company has recognized an asset for this amount, and has recognized corresponding unrealized gain which is included in other income (expenses) during 2012. At December 31, 2011 the Company had oil price swap agreements for 1,440,000 barrels of oil to be produced in 2012 with a fair value of $0.5 million. The Company recognized a current asset for this amount, and recognized an unrealized gain of $0.3 million, net of income taxes of $0.2 million, which was included in other comprehensive income.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table summarizes the changes in the fair values of derivative financial instruments, which are Level 2 liabilities, for the years ended December 31, 2010, 2011 and 2012:
The following table presents the carrying amounts and estimated fair value of the Company’s other financial instruments as of December 31, 2011 and 2012:
The fair market value of the Company’s fixed rate debt was based on the market prices as of December 31, 2011 and 2012, a Level 1 measurement. The fair value of the floating rate debt outstanding at December 31, 2011 and 2012 approximated its carrying value, a Level 2 measurement.
Property and Equipment
The Company follows the successful efforts method of accounting for its oil and gas properties. Acquisition costs for proved oil and gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. Equivalent units are determined by converting oil to natural gas at the ratio of one barrel of oil for six thousand cubic feet of natural gas. This conversion ratio is not based on the price of oil or natural gas, and there may be a significant difference in price between an equivalent volume of oil versus natural gas. Cost centers for amortization purposes are determined on a field area basis. Costs incurred to acquire oil and gas leasehold are capitalized. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related facilities disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense. The costs of unproved properties which are determined to be productive are transferred to proved oil and gas properties and amortized on an equivalent unit-of-production basis. Exploratory expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties, are charged to expense as incurred. Unproved oil and gas properties are periodically assessed for impairment on a property by property basis, and any impairment in value is charged to exploration expense. During 2011 and 2012, impairment charges of $9.8 million and $61.3 million, respectively, were recognized in exploration expense related to certain leases that the Company no longer expects to drill on. Exploratory drilling costs are initially capitalized as unproved property but charged to expense if and when the well is determined not to have found commercial quantities of proved oil and gas reserves. Exploratory drilling costs are evaluated within a one-year period after the completion of drilling.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company periodically assesses the need for an impairment of the costs capitalized for its oil and gas properties on a property or cost center basis. If impairment is indicated based on undiscounted expected future cash flows attributable to the property, then a provision for impairment is recognized to the extent that net capitalized costs exceed the estimated fair value of the property. The fair value is based upon estimated discounted future cash flows which are derived from Level 3 inputs. Expected future cash flows are determined using estimated future prices based on market based forward prices applied to projected future production volumes. Costs are also projected to escalate at a rate that is based upon the Company’s historical experience. The projected production volumes are based on the property’s proved and risk adjusted probable oil and natural gas reserve estimates at the end of the period. The oil and natural gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of an average price based on the first day of each month of the preceding year and is limited to proved reserves. The Company recognized impairment charges related to its oil and gas properties of $0.2 million, $60.8 million and $25.4 million in 2010, 2011, and 2012, respectively.
Other property and equipment consists primarily of gas gathering systems, computer equipment, furniture and fixtures and an airplane which are depreciated over estimated useful lives ranging from three to 31 1/2 years on a straight-line basis.
Other Assets
Other assets primarily consist of deferred costs associated with issuance of the Company’s senior notes and bank credit facility. These costs are amortized over the life of the senior notes and the life of the bank credit facility on a straight-line basis which approximates the amortization that would be calculated using an effective interest rate method.
Accrued Expenses
Accrued expenses at December 31, 2011 and 2012 consist of the following:
Reserve for Future Abandonment Costs
The Company’s asset retirement obligations relate to future plugging and abandonment costs of its oil and gas properties and related facilities disposal. The Company records a liability in the period in which an asset retirement obligation is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter, this liability is accreted up to the final retirement cost. Accretion of the discount is included as part of depreciation, depletion and amortization in the accompanying consolidated financial statements.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table summarizes the changes in the Company’s total estimated liability:
Stock-based Compensation
The Company has stock-based employee compensation plans under which stock awards, comprised of restricted stock, stock options and performance share units are issued to employees and non-employee directors. The Company follows the fair value based method in accounting for equity-based compensation. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period. Excess tax benefits on stock-based compensation are recognized as an adjustment to additional paid-in capital and as a part of cash flows from financing activities.
Segment Reporting
The Company presently operates in one business segment, the exploration and production of oil and natural gas.
Derivative Instruments and Hedging Activities
The Company accounts for derivative instruments (including certain derivative instruments embedded in other contracts) as either an asset or liability measured at its fair value. Changes in the fair value of derivatives are recognized currently in earnings unless specific hedge accounting criteria are met. The Company estimates fair value based on a discounted cash flow model and quotes obtained from the counterparties to the derivative contract. The fair value of derivative contracts that expire in less than one year are recognized as current assets or liabilities. Those that expire in more than one year are recognized as long-term assets or liabilities. Derivative financial instruments that are not accounted for as hedges are adjusted to fair value through income. If the derivative is designated as a cash flow hedge, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings.
Major Purchasers
In 2012 the Company had two purchasers of its oil and natural gas production that accounted for 42% and 27%, respectively, of total oil and gas sales. In 2011 the Company had two purchasers of its oil and natural gas production that accounted for 49% and 14%, respectively, of total oil and gas sales. In 2010 the Company had one purchaser of its oil and natural gas production that accounted for 39% of total oil and gas sales. The loss of any of these customers would not have a material adverse effect on the Company as there is an available market for its oil and natural gas production from other purchasers.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Revenue Recognition and Gas Balancing
Comstock utilizes the sales method of accounting for oil and natural gas revenues whereby revenues are recognized at the time of delivery based on the amount of oil or natural gas sold to purchasers. Revenue is typically recorded in the month of production based on an estimate of the Company’s share of volumes produced and prices realized. Revisions to such estimates are recorded as actual results are known. The amount of oil or natural gas sold may differ from the amount to which the Company is entitled based on its revenue interests in the properties. The Company did not have any significant imbalance positions at December 31, 2011 or 2012. Sales of oil and natural gas generally occur at the wellhead. When sales of oil and gas occur at locations other than the wellhead, the Company accounts for costs incurred to transport the production to the delivery point as operating expenses.
General and Administrative Expenses
General and administrative expenses are reported net of reimbursements of overhead costs that are received from working interest owners of the oil and gas properties operated by the Company of $10.6 million, $10.5 million and $11.5 million in 2010, 2011 and 2012, respectively.
Income Taxes
The Company accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as the future tax consequences attributable to the future utilization of existing tax net operating loss and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that the change in rate is enacted.
Earnings Per Share
Basic earnings per share is determined without the effect of any outstanding potentially dilutive stock options and diluted earnings per share is determined with the effect of outstanding stock options that are potentially dilutive. Unvested share-based payment awards containing nonforfeitable rights to dividends are considered to be participatory securities and included in the computation of basic and diluted earnings per share pursuant to the two-class method. Performance share units (“PSUs”) represent the right to receive a number of shares of the Company’s common stock that may range from zero to up to three times the number of PSUs granted on the award date based on the achievement of certain performance measures during a performance period. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective period, assuming that date was the end of the contingency period. The treasury stock method is used to measure the dilutive effect of PSUs.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Basic and diluted earnings per share for 2010, 2011 and 2012 were determined as follows:
At December 31, 2010, 2011 and 2012, 2,069,275, 2,114,520 and 1,960,835 shares of unvested restricted stock, respectively, are included in common stock outstanding as such shares have a nonforfeitable right to participate in any dividends that might be declared and have the right to vote. Weighted average shares of unvested restricted stock included in common stock outstanding were as follows:
All stock options, unvested stock and PSUs were anti-dilutive to earnings and excluded from weighted average shares used in the computation of earnings per share due to the net loss in each period.
Options to purchase common stock that were outstanding and that were excluded as anti-dilutive from determination of diluted earnings per share were as follows:
Supplementary Information With Respect to the Consolidated Statements of Cash Flows
For the purpose of the consolidated statements of cash flows, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Cash payments made for interest and income taxes for the years ended December 31, 2010, 2011 and 2012, respectively, were as follows:
The Company capitalizes interest on its unevaluated oil and gas property costs during periods when it is conducting exploration activity on this acreage. The Company capitalized interest of $13.0 million, $13.2 million and $20.9 million in 2010, 2011 and 2012, respectively, which reduced interest expense and increased the carrying value of its unevaluated oil and gas properties.
Comprehensive Loss
Comprehensive loss consists of the following:
The following table provides a summary of the amounts included in accumulated other comprehensive income, net of income taxes, for the years ended December 31, 2010, 2011 and 2012:
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Subsequent Events
Subsequent events were evaluated through the issuance date of these consolidated financial statements.
(2) Acquisitions and Dispositions of Oil and Gas Properties
On December 29, 2011, the Company completed an acquisition, from an unrelated party, of oil and gas properties in the Delaware Basin located in Reeves County in West Texas (the “Delaware Basin Acquisition”). Total cash consideration paid of $337.9 million was funded with borrowings under the Company’s bank credit facility. The Company acquired proved oil and gas reserves of 25.2 million barrels of oil equivalent and leases covering 43,591 net acres. The effective date of the acquisition was November 1, 2011. Concurrent with the Delaware Basin Acquisition, Comstock entered into a transaction structured as a reverse like-kind exchange in accordance with Section 1031 of the Internal Revenue Code. In connection with this reverse like-kind exchange, Comstock assigned the right to acquire ownership in the oil and gas properties that were acquired to a variable interest entity formed by an exchange accommodation titleholder. Comstock operated these properties pursuant to lease and management agreements with that entity, and had a call option which allowed the Company to terminate the exchange transaction at any time up and until the expiration date of the exchange. The exchange transaction was completed in May 2012 and the variable interest entity was then merged into a wholly owned subsidiary of the Company. Because the Company was the primary beneficiary of these arrangements, the properties acquired are included in its consolidated balance sheet as of December 31, 2011, and all revenues earned and expenses incurred related to the properties were included in the Company’s consolidated results of operations during the term of the agreements.
The purchase price allocation, including final post-closing adjustments finalized during 2012, was as follows:
Amounts recognized for the fair value of assets acquired and liabilities assumed were as follows:
On December 30, 2011, the Company acquired oil and gas properties in North Louisiana from a third party for $27.1 million. This acquisition included proved oil and gas reserves of 13 billion cubic feet of natural gas equivalent and leases covering 3,500 net acres.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Comstock considered the property acquisitions as business combinations and estimated the fair value of the properties as of the acquisition date. To estimate the fair value of the properties, the Company used a net asset value approach. The Company utilized a discounted cash flow model that took into account the following inputs to arrive at estimates of future net cash flows:
•
Estimated ultimate recovery of oil and natural gas;
•
Estimated future commodity prices based on NYMEX oil and natural gas futures prices adjusted for estimated location and quality differentials as well as related transportation costs;
•
Estimated future production rates; and
•
Estimated timing and amounts of future operating and development costs.
To estimate the fair value of proved properties, the Company discounted the future net cash flows using a market-based rate that the Company determined appropriate at the acquisition date for the various proved reserve categories. Due to the unobservable nature of the inputs, the fair values of the proved and unproved oil and gas properties are considered Level 3 fair value measurements.
During 2012, the Company completed the sale of certain oil and gas properties located in Tyler and Polk counties in South Texas and Lincoln Parish in North Louisiana. The Company received aggregate net proceeds of $119.8 million and recognized a total gain of $26.0 million from these transactions. Also during 2012, the Company completed the sale of certain non-operated oil and gas properties acquired as part of the Delaware Basin Acquisition and received net proceeds of $24.8 million. The Company accounted for the disposal of these properties as a retirement since they represented a small portion of the assets within one of its major oil and gas properties.
On July 30, 2012, the Company entered into a participation agreement with Kohlberg Kravis Roberts & Co L.P. (together with its affiliates, “KKR”) providing for the participation of KKR in Comstock’s future development of its Eagle Ford shale properties in South Texas. Under the terms of the participation agreement, KKR has the right to participate for one-third of Comstock’s working interest in wells drilled on the Company’s 28,160 net acres in exchange for KKR paying $25,000 per acre for the net acreage being acquired and one-third of the wells costs. Each well that KKR participates in is intended to earn KKR approximately one-third of the Company’s working interest in approximately 80 acres. The agreement applies to wells spud by the Company on or subsequent to March 31, 2012. The Company retains all of its interest in wells that were spud prior to March 31, 2012. Subject to certain conditions, KKR is obligated to acquire acreage for the first 100 wells drilled on the Company’s Eagle Ford Shale acreage after July 30, 2012 and can continue to participate in additional wells drilled on the acreage under the same terms. Comstock received $23.8 million from KKR to fund its participation in drilling activity before the closing on July 30, 2012. During 2012 the Company also received $8.7 million for acreage and facility costs for new wells drilled subsequent to the closing. The Company accounted for the receipt of these funds as a retirement since they represented a small portion of the costs within one of its major oil and gas properties. Formation costs of $1.7 million incurred in connection with this joint venture are reflected as a reduction to the realized gain on sale of oil and gas properties in the consolidated financial statements.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(3) Oil and Gas Producing Activities
Set forth below is certain information regarding the aggregate capitalized costs of oil and gas properties and costs incurred by the Company for its oil and gas property acquisition, development and exploration activities:
Capitalized Costs
Costs Incurred
(4) Long-term Debt
Long-term debt is comprised of the following:
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The discount on the 8 3/8% and 9 1/2% senior notes are being amortized over the life of the senior notes using the effective interest rate method.
The following table summarizes Comstock’s debt as of December 31, 2012 by year of maturity:
Comstock has a $850.0 million bank credit facility with Bank of Montreal, as the administrative agent. The credit facility is a five year revolving credit commitment that matures on November 30, 2015. Indebtedness under the credit facility is secured by substantially all of Comstock’s assets and is guaranteed by all of its wholly owned subsidiaries. The credit facility is subject to borrowing base availability, which is redetermined semiannually based on the banks’ estimates of the Company’s future net cash flows of oil and natural gas properties. The borrowing base may be affected by the performance of Comstock’s properties and changes in oil and natural gas prices. The determination of the borrowing base is at the sole discretion of the administrative agent and the bank group. As of December 31, 2012, the borrowing base was $570.0 million, $130.0 million of which was available. Borrowings under the credit facility bear interest, based on the utilization of the borrowing base, at Comstock’s option at either (1) LIBOR plus 1.75% to 2.75% or (2) the base rate (which is the higher of the administrative agent’s prime rate, the federal funds rate plus 0.5% or 30 day LIBOR plus 1.0%) plus 0.75% to 1.75%. A commitment fee of 0.5% is payable annually on the unused borrowing base. The credit facility contains covenants that, among other things, restrict the payment of cash dividends in excess of $50.0 million, limit the amount of consolidated debt that Comstock may incur and limit the Company’s ability to make certain loans and investments. The only financial covenants are the maintenance of a ratio of current assets, including availability under the bank credit facility, to current liabilities and maintenance of a leverage ratio. The Company was in compliance with these covenants as of December 31, 2012.
On June 5, 2012 the Company issued $300.0 million of senior notes (the “2020 Notes”) pursuant to an underwritten public offering. The 2020 Notes are due on June 15, 2020 and bears interest at 9 1/2%, which is payable semi-annually on each June 15 and December 15. Proceeds from the issuance of the 2020 Notes were used to pay down outstanding borrowings under the Company’s bank credit facility. On March 14, 2011, Comstock issued $300.0 million of senior notes (the “2019 Notes”) pursuant to an underwritten public offering. The 2019 Notes are due on April 1, 2019 and bear interest at 7 3/4%, which is payable semiannually on each April 1 and October 1. Comstock also has $300.0 million of 8 3/8% senior notes outstanding which mature on October 15, 2017 (the “2017 Notes”). Interest on the 2017 Notes is payable semiannually on each April 15 and October 15. The 2017, 2019 and 2020 Notes are unsecured obligations of Comstock and are guaranteed by all of Comstock’s material subsidiaries. Such subsidiary guarantors are 100% owned and all of the guarantees are full and unconditional and joint and several obligations. As of December 31, 2012, Comstock had no material assets or operations which are independent of its subsidiaries. There are no restrictions on the ability of Comstock to obtain funds from its subsidiaries through dividends or loans.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
On January 1, 2011, Comstock had $172.0 million in principal amount of 6 7/8% senior notes outstanding due in 2012 (the “2012 Notes”). Comstock redeemed all of the 2012 Notes in March 2011 for $172.4 million. The early extinguishment of the 2012 Notes resulted in a loss of $1.1 million which is included in interest expense in the consolidated financial statements. This loss is comprised of the premium paid for the redemption of the 2012 Notes, the costs incurred related to the tender offer, and the write-off of unamortized debt issuance costs related to the 2012 Notes.
(5) Commitments and Contingencies
Commitments
The Company rents office space and other facilities under noncancelable operating leases. Rent expense for the years ended December 31, 2010, 2011 and 2012 was $1.3 million, $1.1 million and $1.4 million, respectively. Minimum future payments under the leases are as follows:
As of December 31, 2012, the Company had commitments for contracted drilling rigs of $65.3 million through November 2015.
The Company has entered into natural gas transportation agreements through July 2019. Maximum commitments under these transportation agreements as of December 31, 2012 totaled $25.3 million.
Contingencies
From time to time, the Company is involved in certain litigation that arises in the normal course of its operations. The Company records a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. The Company does not believe the resolution of these matters will have a material effect on the Company’s financial position or results of operations and no material amounts are accrued relative to these matters at December 31, 2011 or 2012.
(6) Stockholders’ Equity
The authorized capital stock of Comstock consists of 75 million shares of common stock, $.50 par value per share, and 5 million shares of preferred stock, $10.00 par value per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors. There were no shares of preferred stock outstanding at December 31, 2011 or 2012.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(7) Stock-based Compensation
The Company grants restricted shares of common stock, stock options and performance share units to key employees and directors as part of their compensation under the 2009 Long-term Incentive Plan. Future awards of stock options, restricted stock grants or other equity awards under the 2009 Long-term Incentive Plan are available with up to 1,607,372 shares of common stock.
During 2010, 2011 and 2012, the Company had $17.4 million, $15.0 million and $13.7 million, respectively, in stock-based compensation expense which is in general and administrative expenses. The excess income tax benefit realized from tax deductions associated with stock-based compensation recognized in additional paid in capital totaled $1.5 million in 2010 and excess tax provisions from tax deductions associated with stock-based compensation of $0.6 million and $1.7 million were recognized in additional paid in capital for the years ended December 31, 2011 and 2012, respectively.
Stock Options
The Company amortizes the fair value of stock options granted over the vesting period using the straight-line method. Compensation expense recognized for outstanding stock options was $0.4 million for the year ended December 31, 2010.
The Company has not issued any stock options since 2008. The following table summarizes information related to stock options outstanding at December 31, 2012:
The following table summarizes information related to stock option activity under the Company’s incentive plans for the year ended December 31, 2012:
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
As of December 31, 2012, all compensation cost related to stock options had been recognized. Stock options outstanding at December 31, 2011 and 2012 had no intrinsic value based on the closing price for the Company’s common stock on December 31, 2011 and December 31, 2012. There were no stock option exercises in 2011 or 2012.
Restricted Stock
The fair value of restricted stock grants is amortized over the vesting period, generally one to four years, using the straight-line method. Total compensation expense recognized for restricted stock grants was $17.0 million, $15.0 million and $13.5 million for the years ended December 31, 2010, 2011 and 2012, respectively. The fair value of each restricted share on the date of grant is equal to its fair market price. A summary of restricted stock activity for the year ended December 31, 2012 is presented below:
The per share weighted average fair value of restricted stock grants in 2010, 2011 and 2012 was $25.61, $18.31 and $15.49, respectively. Total unrecognized compensation cost related to unvested restricted stock of $19.1 million as of December 31, 2012 is expected to be recognized over a period of 2.3 years. The fair value of restricted stock which vested in 2010, 2011 and 2012 was $15.1 million, $9.3 million and $6.7 million, respectively.
Performance Share Units
The Company issues PSUs as part of its long-term equity incentive compensation. PSU awards can result in the issuance of common stock to the holder if certain performance criteria is met during a performance period. The performance periods consist of one year, two years and three years, respectively. The performance criteria for the PSUs are based on the Company’s annualized total stockholder return (“TSR”) for the performance period as compared with the TSR of certain peer companies for the performance period. The costs associated with PSUs are recognized as general and administrative expense over the performance periods of the awards.
The fair value of PSUs was measured at the grant date using a stochastic process method utilizing the Geometric Brownian Motion Model (“GBM Model”). A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the future performance periods. By using a stochastic simulation, the Company can create multiple prospective total return pathways, statistically analyze these simulations, and ultimately make inferences to the most likely path the total return will take. As such, because future stock returns are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an appropriate method by which to
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility and a risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the vesting periods, as well as the volatilities for each of the Company’s peers. For the PSUs granted in 2012, the valuation inputs included a risk-free interest rate of 0.4% and a range of volatilities of 29% to 70%.
The Company granted 254,133 PSUs in 2012, all of which were outstanding at December 31, 2012, with a grant date fair value of $5.4 million, or $21.14 per unit. The number of awards assumes a one multiplier. The final number of shares of common stock issued may vary depending upon the performance multiplier, and can result in the issuance of zero to 688,545 shares of common stock based on the achieved performance ranges from zero to three.
Total compensation expense for PSUs was $0.2 million for the year ended December 31, 2012. As of December 31, 2012, there was $5.2 million of total unrecognized expense related to PSUs, which is being amortized through December 2015.
(8) Retirement Plan
The Company has a 401(k) profit sharing plan which covers all of its employees. At its discretion, Comstock may match a certain percentage of the employees’ contributions to the plan. Matching contributions to the plan were $341,000, $323,000 and $365,000 for the years ended December 31, 2010, 2011 and 2012, respectively.
(9) Income Taxes
The following is an analysis of the consolidated income tax benefit:
Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. The difference between the Company’s customary rate of 35% and the effective tax rate on income before income taxes is due to the following:
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The tax effects of significant temporary differences representing the net deferred tax asset and liability at December 31, 2011 and 2012 were as follows:
At December 31, 2012, Comstock had the following carryforwards available to reduce future income taxes:
Utilization of $36.9 million of the U.S. federal net operating loss carryforwards is limited to approximately $1.1 million per year pursuant to a prior change of control of an acquired company, and a
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
valuation allowance of $23.0 million, with a tax effect of $8.0 million, has been established for the estimated U.S. federal net operating loss carryforwards that will not be utilized. Realization of the remaining U.S. federal net operating loss carryforwards requires Comstock to generate taxable income within the carryforward period. A valuation allowance of $288.0 million, with a tax effect of $15.0 million, has been established against the Louisiana state net operating loss carryforwards due to the uncertainty of generating taxable income in the state of Louisiana prior to the expiration of the carryforward period.
The Company’s federal income tax returns for the years subsequent to December 31, 2007 remain subject to examination. The Company’s income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2007. State tax returns in two state jurisdictions are currently under review. The Company currently believes that resolution of these matters will not have a material impact on its financial statements. The Company currently believes that its significant filing positions are highly certain and that all of its other significant income tax filing positions and deductions would be sustained upon audit or the final resolution would not have a material effect on the consolidated financial statements. Therefore, the Company has not established any significant reserves for uncertain tax positions. Interest and penalties resulting from audits by tax authorities have been immaterial and are included in the provision for income taxes in the consolidated statements of operations.
(10) Derivative Financial Instruments and Hedging Activities
Comstock periodically uses swaps, floors and collars to hedge oil and natural gas prices and interest rates. Swaps are settled monthly based on differences between the prices specified in the instruments and the settlement prices of futures contracts. Generally, when the applicable settlement price is less than the price specified in the contract, Comstock receives a settlement from the counterparty based on the difference multiplied by the volume or amounts hedged. Similarly, when the applicable settlement price exceeds the price specified in the contract, Comstock pays the counterparty based on the difference. Comstock generally receives a settlement from the counterparty for floors when the applicable settlement price is less than the price specified in the contract, which is based on the difference multiplied by the volumes hedged. For collars, generally Comstock receives a settlement from the counterparty when the settlement price is below the floor and pays a settlement to the counterparty when the settlement price exceeds the cap. No settlement occurs when the settlement price falls between the floor and cap.
During 2012, the Company hedged 1,710,000 barrels of its oil production at an average NYMEX West Texas Intermediate (“WTI”) oil price of $99.46 per barrel. As of December 31, 2012, the Company had the following outstanding commodity derivatives:
The Company recognizes the realized gains and losses, and the unrealized gains and losses due to the change in the fair value of its derivative financial instruments, as separate components of other income (expenses). The Company had realized gains of $9.8 million on its oil swaps that settled during
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
2012. The estimated fair value of the Company’s derivative financial instruments, which equals their carrying value, was an asset of $11.7 million as of December 31, 2012, which is reflected as a current asset based on estimated settlement dates.
(11) Supplementary Quarterly Financial Data (Unaudited)
Basic and diluted per share amounts are the same for each of the quarters ended December 31, 2011, September 30, 2012, December 31, 2012 and for the years ended December 31, 2011 and December 31, 2012 due to the net loss reported during each of these periods.
Results of operations include the following non-routine items of income (expense), which are presented before the effect of income taxes:
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company is restating its financial statements for each of the fiscal quarters ended March 31, 2012, June 30, 2012, and September 30, 2012 with respect to the accounting and disclosures for certain derivative financial transactions under Accounting Standards Codification Topic 815, Derivatives and Hedging (“ASC 815”). The Company determined that the formal documentation it had prepared to support its initial hedge designations for effectiveness in connection with the Company’s oil hedging program was not compliant with the technical documentation requirements to qualify for cash flow hedge accounting treatment in accordance with ASC 815, and as a result, the Company was not permitted to utilize hedge accounting treatment in the preparation of its financial statements. The restatements eliminate hedge accounting treatment which had been applied in 2012 and reflect other immaterial adjustments to oil and gas sales.
Under ASC 815, the fair value of hedge contracts is recognized in the Company’s consolidated balance sheet as an asset or liability, as the case may be, and the amounts received or paid under the hedge contracts are reflected in earnings during the period in which the underlying production occurs. If the hedge contracts qualify for cash flow hedge accounting treatment, the fair value of the hedge contract is recorded in “accumulated other comprehensive income”, and changes in the fair value do not affect net income in the period. If the hedge contract does not qualify for hedge accounting treatment, the change in the fair value of the hedge contract is reflected in earnings during the period as unrealized gain or loss from derivatives. Under the cash flow hedge accounting treatment used by the Company, the fair value of the hedge contracts were recognized in the consolidated balance sheet with the resulting unrealized gain or loss recorded initially in “accumulated other comprehensive income” and later reclassified through earnings when the hedged production impacted earnings. As a result of the determination that the designation documentation failed to meet the requirements necessary to utilize cash flow hedge accounting treatment, the unrealized gain or loss should have been recorded in the consolidated statements of operations as a component of earnings. The Company has also been recognizing realized gains and losses from its derivative financial instruments in oil and gas sales, and is reclassifying these amounts as a separate component of non-operating income and expense.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following tables present the restated condensed consolidated statements of operations and statements of other comprehensive income (loss) for the three months ended March 31, 2012, June 30, 2012 and September 30, 2012 and the nine months ended September 30, 2012, the restated condensed consolidated balance sheets as of March 31, 2012, June 30, 2012 and September 30, 2012, the consolidated statement of stockholders’ equity for the nine months ended September 30, 2012 and the condensed consolidated statements of cash flows for the three months ended March 31, 2012, the six months ended June 30, 2012 and the nine months ended September 30, 2012:
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(Unaudited)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(12) Oil and Gas Reserves Information (Unaudited)
Set forth below is a summary of the changes in Comstock’s net quantities of oil and natural gas reserves for each of the three years ended December 31, 2012:
During 2012, the Company’s estimated quantities of proved undeveloped natural gas reserves decreased by 460 Bcf from total proved undeveloped reserves as of December 31, 2011 due to downward revisions related to the lower natural gas price that was used to determine estimated reserve quantities at December 31, 2012. Substantially all of the Company’s proved undeveloped natural gas reserves related to undrilled natural gas wells at December 31, 2011 were not economic at the lower natural gas price at December 31, 2012. The decrease in proved undeveloped natural gas reserves in 2012 resulted in an increase to the Company’s per unit amortization rate for its proved oil and gas properties and, accordingly, increased depletion, depreciation and amortization expense during 2012 as compared to previous periods.
The proved oil and gas reserves utilized in the preparation of the financial statements were estimated by Lee Keeling and Associates, independent petroleum consultants, in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board, which require that reserve reports be prepared under existing economic and operating conditions with no provision for price and cost escalation except by contractual agreement. All of the Company’s reserves are located onshore in the continental United States of America.
COMSTOCK RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table sets forth the standardized measure of discounted future net cash flows relating to proved reserves at December 31, 2011 and 2012:
The standardized measure of discounted future net cash flows at the end of 2011 and 2012 was determined based on the simple average of the first of month market prices for oil and natural gas for each year. Prices were $92.93 per barrel of oil and $4.18 per Mcf of natural gas for 2011 and $94.61 per barrel of oil and $2.84 per Mcf of natural gas for 2012. Prices used in determining quantities of oil and natural gas reserves and future cash inflows from oil and natural gas reserves represent prices received at the Company’s sales point. These prices have been adjusted from posted or index prices for both location and quality differences. Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing proved oil and gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate statutory tax rates to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect to permanent differences and tax credits, but do not reflect the impact of future operations.
The following table sets forth the changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 2010, 2011 and 2012: