Item 1A. RISK FACTORS
Our business activities are subject to significant hazards and risks, including those described below. If any of these events should occur, our business, financial condition, liquidity or results of operations could be materially adversely affected. Please also refer to the cautionary note under “Forward-Looking Statements” on page 1 of this Annual Report.
Risks Relating to Our Business
Hedging transactions may limit our potential gains or expose us to loss.
To manage our exposure to price risks in the marketing of our natural gas, we enter into natural gas fixed-price physical delivery contracts as well as commodity price swap and collar contracts from time to time with respect to a portion of our current or future production. In connection with the Merger, we became a party to a long-term hedging program (the “Hedges”) with J. Aron and Company (“J. Aron”) under a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”). We anticipate the hedges will cover approximately 63% of the expected 2007 through 2013 production from our current estimated proved reserves. These transactions may limit our potential gains if natural gas prices were to rise substantially over the prices specified in the hedge agreement. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
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our production is less than expected;
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there is a narrowing of price differentials between delivery points for our production and the delivery points assumed in the hedge arrangements;
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there is a failure of a hedge counterparty to perform under the Hedge Agreement or other hedge transactions; or
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a sudden, unexpected event materially impacts natural gas and crude oil prices.
Our operations require large amounts of capital that may not be recovered or raised.
If our revenues were to decrease due to lower oil and natural gas prices, decreased production or other reasons, and if we could not obtain capital through our credit facilities or otherwise, our ability to execute our development plans, replace our reserves or maintain our production levels could be greatly limited. Our current development plans will require us to make large capital expenditures for the exploitation and development of our natural gas properties. Historically, we have funded our capital expenditures through a combination of funds generated internally from sales of production or properties, the issuance of equity, long-term debt financing and short-term financing arrangements. We cannot assure you, however, that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our Amended Credit Agreement and the $40 million letter of credit facility (collectively, the “Senior Facilities”) in an amount sufficient to enable us to pay our indebtedness, including the Senior Secured Notes (“Notes”) or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including the Notes on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including our new Senior Facilities and the Notes, on commercially reasonable terms or at all. Future cash flows and the availability of financing will be subject to a number of variables, such as:
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the success of our projects in the Appalachian and Michigan basins;
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our success in locating and producing new reserves;
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the level of production from existing wells; and
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prices of oil and natural gas.
In addition, debt financing could lead to a diversion of cash flow to satisfy debt servicing obligations and to restrictions on our operations.
Oil and natural gas prices are volatile, and an extended decline in prices would hurt our profitability and financial condition.
While we have entered into long-term hedges covering most of our production in an effort to mitigate the risk of a decline in prices for oil and gas, a portion of our production remains unhedged. We expect that the markets for oil and gas will continue to be volatile. Any substantial or extended decline in the price of oil or gas would negatively affect our financial condition and results of operations. Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and gas properties depend heavily on prevailing market prices for oil and gas. A material decline could reduce our cash flow and borrowing capacity, as well as the value and the amount of our natural gas reserves. Substantially all of our proved reserves are natural gas. Therefore, we are more directly impacted by volatility in the price of natural gas. Various factors beyond our control can affect prices of natural gas. These factors include: North American supplies of oil and gas; political instability or armed conflict in oil or gas producing regions; the price and level of foreign imports; worldwide economic conditions; marketability of production; the level of consumer demand; the price, availability and acceptance of alternative fuels; the availability of pipeline capacity; weather conditions; and actions of federal, foreign, state, and local authorities.
These external factors and the volatile nature of the energy markets make it difficult to estimate future commodity prices.
If oil and natural gas prices decrease or our drilling efforts are unsuccessful, we may be required to write down the carrying value of our oil and natural gas properties.
There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings and stockholders’ equity. A write down could occur when oil and gas prices are low or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results.
We account for our natural gas and crude oil exploration and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas properties may not
exceed the estimated future net cash flows from our properties. If capitalized costs exceed future net revenues, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but it will reduce our earnings and stockholders’ equity.
The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive but may actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area.
We review our oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a write down of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the recorded book values associated with oil and gas properties.
Information concerning our reserves and future net revenues is uncertain.
This Annual Report and our SEC filings contain estimates of our estimated proved oil and natural gas reserves and the estimated future net revenues from such reserves. Actual results will most likely vary from amounts estimated, and any significant variance could have a material adverse effect on our future results of operations.
Reserve estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data and these differences may be significant. Therefore, these estimates are not precise.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed by us. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
At December 31, 2006, approximately 20% of our estimated proved reserves were proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is nearly always based on analogy to existing wells rather than the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Production revenues from estimated proved developed non-producing reserves will not be realized until some time in the future. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our reserves and the costs associated with these reserves in accordance with industry standards, these estimated costs may not be accurate, development may not occur as scheduled and actual results may not be as estimated.
Analysts and investors should not construe the present value of future net reserves, or PV-10, as the current market value of the estimated oil and natural gas reserves attributable to our properties. We have based the estimated discounted future net cash flows from estimated proved reserves on prices and costs as of the date of the estimate, in accordance with applicable regulations, whereas actual future prices and costs may be materially higher or lower. Many factors will affect actual future net cash flows, including:
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the amount and timing of actual production;
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supply and demand for natural gas;
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curtailments or increases in consumption by natural gas purchasers; and
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changes in governmental regulations or taxation.
The timing of the production of oil and natural gas and of the related expenses affect the timing of actual future net cash flows from estimated proved reserves and, thus, their actual present value. In addition, the 10% discount factor, which we are required to use to calculate PV-10 for reporting purposes, is not necessarily the most appropriate discount factor given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.
Our exploitation and development drilling activities may not be successful.
Our future drilling activities may not be successful, and we cannot assure you that our overall drilling success rate or our drilling success rate for activity within a particular area will not decline. In addition, the wells that we drill may not recover all or any portion of our capital investment in the wells, infrastructure, or the underlying leaseholds. Unsuccessful drilling activities could negatively affect our results of operations and financial condition. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations, including:
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unexpected drilling conditions;
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pressure or irregularities in formations;
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equipment failures or accidents;
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ability to hire and train personnel for drilling and completion services;
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adverse weather conditions;
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compliance with governmental requirements; and
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shortages or delays in the availability of drilling rig services and the delivery of equipment.
In addition, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. There is no guarantee that the potential drilling locations that we have identified will ever produce oil or natural gas.
If our development drilling activities are not successful, we may not be able to replace or grow our reserves.
Our acquisition activities may not be successful.
As part of our growth strategy, we may make additional acquisitions of businesses and properties. However, suitable acquisition candidates may not be available on terms and conditions we find acceptable, and acquisitions pose substantial risks to our business, financial condition and results of operations. In pursuing acquisitions, we compete with other companies, many of which have greater financial and other resources to acquire attractive companies and properties. Even if future acquisitions are completed, the following are some of the risks associated with acquisitions:
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some of the acquired businesses or properties may not produce revenues, earnings or cash flow at anticipated levels;
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we may assume liabilities that were not disclosed or that exceed our estimates;
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we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;
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acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and
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we may incur additional debt related to future acquisitions.
If our acquisition activities are not successful, our ability to replace or grow our reserves may be limited.
We face strong competition in the oil and natural gas industry, and the resources of many of our competitors are greater than ours.
We operate in a highly competitive industry. We compete with major oil companies, independent producers and institutional and individual investors, who are actively seeking oil and natural gas properties throughout the world, along with the equipment, labor and materials required to operate properties. Many of our competitors have financial and technological
resources vastly exceeding those available to us. Many oil and natural gas properties are sold in a competitive bidding process in which we may lack technological information or expertise available to other bidders. We cannot assure you that we will be successful in acquiring and developing profitable properties in the face of this competition.
Our operations are subject to the business and financial risk of oil and natural gas exploration.
The business of exploring for and, to a lesser extent, developing oil and natural gas properties is an activity that involves a high degree of business and financial risk. Property acquisition decisions generally are based on various assumptions and subjective judgments that are speculative. It is impossible to predict accurately the ultimate production potential, if any, of a particular property or well. Moreover, the successful completion of an oil or natural gas well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomic or marginally economic.
Our business is subject to operating hazards that could result in substantial losses.
The oil and natural gas business involves operating hazards such as well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks, any of which could cause us a substantial loss. In addition, we may be held liable for environmental damage caused by previous owners of property that we own or lease. As a result, we may face substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for operation, development, production or acquisitions or cause us to incur losses. An event that is not fully covered by insurance (for example losses resulting from pollution and environmental risks, which are not fully insurable) could have a material adverse effect on our financial condition and results of operations.
We must comply with complex federal, state and local laws and regulations.
Federal, state, and local authorities extensively regulate the oil and natural gas industry. Noncompliance with these statutes and regulations may lead to substantial penalties, and the overall regulatory burden on the industry increases the cost of doing business and, in turn, decreases profitability. Regulations affect various aspects of oil and natural gas drilling and production activities, including the pricing and marketing of oil and natural gas production, the drilling of wells (through permit and bonding requirements), the positioning of wells, the unitization or pooling of oil and natural gas properties, environmental matters, safety standards, the sharing of markets, production limitations, plugging and abandonment, and restoration. These laws and regulations are under constant review for amendment or expansion.
We may incur substantial costs to comply with stringent environmental regulations.
Our operations are subject to stringent and constantly changing environmental laws and regulations adopted by federal, state, and local governmental authorities. We could be forced to expend significant resources to comply with new laws or regulations, or changes to current requirements. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between governmental environmental agencies. We could face significant liabilities to the government and third parties for discharges of oil, natural gas or other pollutants into the air, soil or water, and we could have to spend substantial amounts on investigations, litigation and remediation, as well as our efforts to prevent future spills. Moreover, our failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and the issuance of injunctions that restrict or prohibit the performance of operations. See “Items 1 and 2 - Business and Properties - Regulation.”
Our business depends on gathering and transportation facilities owned by others.
The marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties, and changes in our contracts with these third parties could materially affect our operations.
In addition, federal, state, and local regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, and general economic conditions could adversely affect our ability to gather or transport our oil and natural gas. “Items 1 and 2 - Business and Properties - Regulation.”
All of our common stock is owned by one controlling shareholder whose interests may differ from those of the holders of our Notes.
We are a wholly owned subsidiary of Capital C. As a result of this ownership, Capital C is able to direct the election of our Board of Directors and therefore, direct our management and policies. Capital C may unilaterally approve mergers
and other fundamental corporate changes involving us, which require shareholder approval. The interests of Capital C as shareholder may differ from the interests of holders of our Notes. See “Item 13 - Certain Relationships and Related Transactions.”
Our structure may present conflicts of interest.
Our sole shareholder, Capital C, is owned by institutional funds managed by EnerVest. Messrs. Houser and Vanderhider are Executive officers of EnerVest. EnerVest manages other funds that own interests in oil and gas properties in our area of operations. Mr. Mariani is an Executive officer of EnerVest Operating L.L.C. (“EnerVest Operating”), a subsidiary of EnerVest. EnerVest Operating controls the operations of our wells and the wells owned by other EnerVest managed funds. We can give no assurance that conflicts of interest will not arise with respect to corporate opportunities. Also, we can give no assurance that conflicts will not arise with respect to the time and attention devoted to us by Messrs. Houser, Vanderhider and Mariani.
The terms of our Senior Facilities, as well as the Hedges and the indenture relating to the Notes, restrict our current and future operations, particularly our ability to respond to industry or economic changes or to take certain actions.
Our Senior Facilities and the Hedge Agreement contain, and any future refinancing of our Senior Facilities likely would contain, a number of restrictive covenants that impose significant operating and financial restrictions on us. Our Senior Facilities and, to some extent, the Hedge Agreement include covenants restricting, among other things, our ability to:
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incur additional debt;
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pay dividends and make investments, loans or advances;
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incur capital expenditures;
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create liens;
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use the proceeds from sales of assets and capital stock;
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enter into sale and leaseback transactions;
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enter into transactions with affiliates;
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transfer all or substantially all of our assets; and
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enter into merger or consolidation transactions.
Our Senior Facilities also include financial covenants, including requirements that we maintain:
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a minimum interest coverage ratio;
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a maximum total leverage ratio; and
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a minimum current ratio.
The indenture relating to the Notes also contains covenants including, among other things, restrictions on our ability to:
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incur additional indebtedness;
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pay dividends or make other distributions on stock, redeem stock or redeem subordinated obligations;
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make investments;
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create liens or other encumbrances; and
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sell or otherwise dispose of all or substantially all of our assets, or merge or consolidate with another entity.
A failure to comply with the covenants contained in our Senior Facilities or the indenture could result in an event of default (or an event of default under the Hedge Agreement which would result in an event of default under the Senior Facilities), which could materially and adversely affect our operating results and our financial condition. In the event of any default under our Senior Facilities or an event of default under the Hedge Agreement, the lenders under our Senior Facilities, or the Hedge counterparty, respectively, could elect to declare all borrowings outstanding or obligations thereunder, together with accrued and unpaid interest and fees, to be due and payable, and to require us to apply all of our available cash to repay the obligations owing to such entities, which would be an event of default under the Notes. In addition, our existing debt and any new debt may impose financial restrictions and other covenants on us that may be more restrictive than those applicable to the Notes.
Item 1B.
Item 1B. UNRESOLVED STAFF COMMENTS
None.
Item 3.
Item 3. LEGAL PROCEEDINGS
In February 2000, four individuals filed a suit in Chautauqua County, New York on their own behalf and on the behalf of others similarly situated, seeking damages for the alleged difference between the amount of lease royalties actually paid and the amount of royalties that allegedly should have been paid. Other natural gas producers in New York were served with similar complaints. On October 10, 2005, we were granted a summary judgment that dismissed all claims. The plaintiff filed a notice of appeal and had nine months to file their brief. Our counsel has advised us that the plaintiffs in this case have failed to file their appeal timely, therefore our summary judgement stands and the case is dismissed.
We are involved in several lawsuits arising in the ordinary course of business. We believe that the result of such proceedings, individually or in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
Item 5.
Item 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
There is no established public trading market for our equity securities.
All of our equity securities at March 5, 2007, were held by Capital C.
Dividends
We paid cash dividends of $20.0 million in 2006 and $8.5 million in the fourth quarter of 2005. No dividends were paid on our Common Stock prior to the fourth quarter of 2005. We expect to continue to pay dividends on a monthly basis.
Equity Compensation Plan Information:
We have a 1997 non-qualified stock option plan under which we are authorized to issue up to 1,466 shares of common stock to officers and employees. No options were granted during 2005 or 2006 and as of December 31, 2006, no options were outstanding under the plan. We have no intentions to grant any options under the plan.
Item 6.
Item 6. SELECTED FINANCIAL DATA
The Selected Financial Data should be read in conjunction with the Consolidated Financial Statements at Item 15(a).
(1)
See Note 4 to the Consolidated Financial Statements for information on discontinued operations.
Item 7.
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
We are an Ohio corporation wholly owned by Capital C Energy Operations, LP, a Delaware limited partnership (“Capital C”). Capital C acquired us pursuant to a merger completed on July 7, 2004 (the “Merger”). On August 16, 2005, Capital C was acquired by institutional funds managed by EnerVest Management Partners, Ltd. (“EnerVest”), a Houston-based privately held oil and gas operator and institutional funds manager (the “Transaction”). The Transaction resulted in a change in control of the Company (“Change in Control”).
We are an independent energy company engaged in the exploitation, development, production, operation and acquisition of oil and natural gas properties. Our operations are focused in the Appalachian Basin in Ohio, Pennsylvania and New York and in the Antrim Shale formation in the Michigan Basin.
At December 31, 2006, our total estimated proved reserves were 264 Bcfe. Natural gas comprised approximately 88% of our estimated proved reserves, and 80% of our estimated proved reserves were classified as proved developed. Substantially all of our reserves are located in shallow, highly developed formations with long-lived, stable production profiles. At December 31, 2006, our conventional Appalachian properties accounted for 52% of our estimated proved reserves, while the Michigan properties and our Appalachian coalbed methane properties (“CBM”) accounted for 41% and 7%, respectively.
In connection with the Transaction, our then existing indebtedness was refinanced. The principal elements of the refinancing included entering into a $390 million credit facility, comprised of a $350 million revolving facility, which currently has a borrowing base of $113.4 million, and a $40 million letter of credit facility (collectively, the “Senior Facilities”), and our issuance of a $25 million Subordinated Promissory Note with a related party (see Note 18).
During the periods discussed, we earned revenue through the production and sale of oil and natural gas and, to a lesser extent, from gas gathering and marketing. In 2004, we sold the assets of Arrow Oilfield Services (“Arrow”) and substantially all of our interests, or rights to our interests, in our Trenton Black River (“TBR”) operations. Both of these transactions were classified as discontinued operations. Historical information has been restated to remove the TBR properties and Arrow from continuing operations.
Our financial results and cash flows can be significantly impacted as commodity prices fluctuate in response to changing market conditions. We use derivative financial instruments on a significant portion of our oil and natural gas production to reduce the volatility of oil and natural gas prices and to protect cash flow available for our development drilling program. In connection with the acquisition by Capital C, at the effective time of the Merger, we became a party to a long-term hedging program (the “Hedges”) with J. Aron under a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”) as required by the Senior Facilities and the indenture governing the Notes, we will maintain such Hedges with J. Aron or its successor permitted assigns. We anticipate that the Hedges will cover approximately 63% of the expected 2007 through 2013 production from our current estimated proved reserves and will range from 58% to 71% of such expected production in any year.
The average price realized for our natural gas, inclusive of qualified effective hedges, increased from $5.80 per Mcf in 2004 to $8.57 per Mcf in 2005 and then increased to $8.77 per Mcf in 2006. The monthly average settle for natural gas trading on the NYMEX increased from $6.14 per Mmbtu (Million British thermal units) in 2004 and to $8.62 per Mmbtu in 2005 and then decreased to $7.23 per Mmbtu in 2006. Our selling price of natural gas is generally higher than the NYMEX price due to the proximity of our operations to natural gas markets along with a favorable Btu (“British thermal unit”) content of our gas. During 2006, our average per unit gas prices (excluding the effects of hedging) in Appalachia and Michigan were $0.37 and $0.05, respectively, higher than the average NYMEX monthly settle price for 2006. The remainder of the difference is primarily due to our qualified hedging activities during these periods. Our average realized price for oil, inclusive of qualified effective hedges, increased from $35.47 per Bbl in 2004 to $46.37 per Bbl in 2005 and to $62.78 per Bbl in 2006.
CRITICAL ACCOUNTING POLICIES
We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States (“GAAP”) and SEC guidance. See the “Notes to Consolidated Financial Statements” included in “Item 8.
Financial Statements and Supplementary Data” for a more comprehensive discussion of our significant accounting policies. GAAP requires information in financial statements about the accounting principles and methods used and the risks and uncertainties inherent in significant estimates including choices between acceptable methods. Following is a discussion of our most critical accounting policies:
Successful Efforts Method of Accounting
The accounting for and disclosure of oil and gas producing activities requires our management to choose between GAAP alternatives and to make judgments about estimates of future uncertainties.
We use the “successful efforts” method of accounting for oil and gas producing activities as opposed to the alternate acceptable “full cost” method. Under the successful efforts method, property acquisition and development costs and certain productive exploration costs are capitalized while non-productive exploration costs, which include certain geological and geophysical costs, exploratory dry hole costs and costs of carrying and retaining undeveloped properties, are expensed as incurred. The costs of carrying and retaining undeveloped properties include delay rental payments made on new and existing leases, ad valorem taxes on existing leases and the cost of previously capitalized leases that are written off because the leases were dropped or expired. Exploratory dry hole costs include the costs associated with drilling an exploratory well that has been determined to be a dry hole.
The major difference between the successful efforts method of accounting and the full cost method is under the full cost method of accounting, such exploration costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the net income (loss) of future periods as a component of depletion expense.
Oil and Gas Reserves
Our estimated proved developed and estimated proved undeveloped reserves are all located within the Appalachian and Michigan Basins in the United States. There are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil and gas reserves may not occur in the periods assumed and actual prices realized and actual costs incurred may vary significantly from assumptions used. Estimated proved reserves represent estimated quantities of natural gas and oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Estimated proved developed reserves are estimated proved reserves expected to be recovered through wells and equipment in place and under operating methods being used at the time the estimates were made. The accuracy of a reserve estimate is a function of:
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the quality and quantity of available data;
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the interpretation of that data;
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the accuracy of various mandated economic assumptions; and
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the judgment of the persons preparing the estimate.
Our estimated proved reserve information for the 2004 Predecessor II Company period ended July 6, 2004 and the 2005 Predecessor I Company period ended August 15, 2005, is based on our internal engineering estimates. Our estimated proved reserve information for all other periods included in this Annual Report is based on estimates prepared by independent petroleum consultants. Estimates prepared by others may be higher or lower than these estimates.
Capitalization, Depreciation, Depletion and Impairment of Long-Lived Assets
See the “Successful Efforts Method of Accounting” discussion above. Capitalized costs related to estimated proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties are calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on economic or other factors. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized.
Unproved oil and gas properties are stated at cost and consist of undeveloped leases. These costs are assessed periodically to determine whether their value has been impaired, and if impairment is indicated, the costs are charged to expense.
Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years.
Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is expensed as incurred, and significant renewals and betterments are capitalized.
Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the difference between the fair value and the carrying amount of the asset. Fair value is determined based on management’s outlook of future oil and natural gas prices and estimated future cash flows to be generated by the assets, discounted at a market rate of interest. Impairment of unproved properties is based on the estimated fair value of the property.
Derivatives and Hedging
Our financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. Under the provisions of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, we recognize all derivative financial instruments as either assets or liabilities at fair value. The changes in fair value of derivative instruments not designated as hedges are reported in expense in the consolidated statements of operations as derivative fair value (gain) loss. Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items impact earnings. Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income (loss). Deferred gains and losses on terminated commodity hedges are recognized as increases or decreases in oil and gas revenues during the same periods in which the underlying forecasted transactions are recognized in net income (loss). If there is a discontinuance of a cash flow hedge because it is probable that the original forecasted transaction will not occur, deferred gains or losses are recognized in earnings immediately.
The relationship between hedging instruments and the hedged items must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk, both at inception of the contract on an ongoing basis. We assess effectiveness at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. We discontinue hedge accounting prospectively if we determine that a derivative is no longer highly effective as a hedge or if we decide to discontinue the hedging relationship.
From time to time we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to natural gas price, crude oil price or interest rate volatility and to support our capital expenditure plans. Our derivative financial instruments take the form of swaps or collars. At December 31, 2006, our derivative contracts were comprised of natural gas swaps, crude oil swaps and interest rate swaps, which were placed with major financial institutions that we believe have a minimal credit risk. Qualifying derivative financial instruments are designated as cash flow hedges.
We use NYMEX-based commodity derivative contracts to hedge natural gas, because our natural gas production is sold pursuant to NYMEX-based sales contracts. Beginning July 7, 2004, we had ineffectiveness on the natural gas swaps due to purchase accounting, which created non-zero value derivatives at the time of the Merger. We had collar agreements that could not be redesignated as cash flow hedges because these collars were not effective due to unrealized losses at the date of the Merger. These collars qualified and were designated as cash flow hedges from their inception through the Predecessor II Company period ended July 6, 2004. Although these collars were not deemed to be effective hedges in accordance with the provisions of SFAS 133, we retained these instruments as protection against changes in commodity prices and we recorded the mark-to-market adjustments on these natural gas collars, through 2005, in our income statement. Our NYMEX crude oil swaps were highly effective and were designated as cash flow hedges through August 16, 2005. We had ineffectiveness on the crude oil swaps because the oil is sold locally at a posted price which is different from the NYMEX price. At August 16, 2005, our oil swaps no longer qualified for cash flow hedge accounting because the assessment of effectiveness indicated that they may not be highly effective on an on-going basis. This occurred due to the application of purchase accounting to the derivatives, which created non-zero value derivatives at the time of the Transaction. The changes in the fair values of the natural gas collars since July 7, 2004, the changes in fair value of the oil swaps subsequent to August 15, 2005, the
ineffective portion of the crude oil swaps through August 15, 2005 and the ineffective portion of the natural gas swaps from July 7, 2004 to June 30, 2006 are recorded as “Derivative fair value gain or loss.” As of July 1, 2006, we determined that our gas swaps were no longer highly effective and, therefore, could no longer be designated as cash flow hedges.
Revenue Recognition
Oil and natural gas revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectibility of the revenue is probable. We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under-produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production. There were no material gas imbalances at December 31, 2006 or 2005. Oil and gas marketing revenues are recognized when title passes.
Asset Retirement Obligations
We follow SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 requires us to recognize a liability for the fair value of our asset retirement obligations associated with its tangible, long-lived assets. The majority of our asset retirement obligations recorded relate to the plugging and abandonment (excluding salvage value) of our oil and gas properties.
There has been no significant current period activity with respect to additional retirement obligations, settled obligations, accretion expense and revisions of estimated cash flows. The asset retirement obligations increased as a result of purchase accounting for the Merger in 2004 and the Transaction in 2005, primarily due to a lower discount rate, revised estimates of asset lives on certain oil and gas wells and additional wells having been drilled.
At December 31, 2006, there were no assets legally restricted for purposes of settling asset retirement obligations. A reconciliation of our liability for asset retirement obligations for the years ended December 31, 2006 and 2005 is as follows (in thousands):
Results of Operations
As a result of the Merger in 2004 and the Transaction in 2005, the results of operations for the periods subsequent to July 6, 2004 and August 15, 2005 are not necessarily comparable to those prior to July 7, 2004 and August 16, 2005. The following table combines the Predecessor II Company 188 day period ended July 6, 2004 with the Predecessor I Company 178 day period ended December 31, 2004 for purposes of the discussion of 2004 results. The table also combines the Predecessor I Company 227 day period ended August 15, 2005 with the Successor Company 138 day period ended December 31, 2005 for purposes of the discussion of 2005 results. The following table sets forth financial data for the periods indicated. Dollars are stated in thousands and percentages are stated as a percentage of total revenues.
The following Management’s Discussion and Analysis is based on the results of operations from continuing operations, unless otherwise noted. Accordingly, the discontinued operations have been excluded. See Note 4 to the Consolidated Financial Statements.
Production, Sales Prices and Costs
The following table sets forth certain information regarding our net oil and natural gas production, revenues and expenses for the years indicated. This table includes continuing operations only. The average prices shown in the table include the effects of our qualified effective hedging activities.
(1)
The average prices presented above include non-cash amounts related to our derivatives as a result of purchase accounting for the Merger and the Transaction. Excluding these non-cash amounts from oil and gas sales revenues would result in the following average prices:
Mmcf - Million cubic feet Mmcfe - Million cubic feet equivalent
Mbbl - Thousand barrels
Mcf - Thousand cubic feet Bbl - Barrel
Operating margin (per Mcfe) - average price less production expense and production taxes
2006 Compared to 2005
Revenues
Net operating revenues increased from $154.3 million in 2005 to $158.4 million in 2006. The increase was due to higher oil sales revenues of $6.8 million, partially offset by lower gas sales revenues of $1.7 million and lower gas gathering and marketing revenues of $1.7 million.
Gas volumes sold decreased 456 Mmcf (3%) from 14.6 Bcf in 2005 to 14.1 Bcf in 2006 resulting in a decrease in gas sales revenues of approximately $3.9 million. Oil volumes sold increased approximately 15,000 Bbls (4%) from 358,000 Bbls in 2005 to 373,000 Bbls in 2006 resulting in an increase in oil sales revenues of approximately $670,000. The lower gas sales volumes are due to normal production declines partially offset by production from new wells drilled in 2006. The increase in oil sales volumes sold was primarily due to production from new wells drilled during 2006 in the Clarendon formation in Pennsylvania, partially offset by normal production declines.
The average price realized for our natural gas increased $0.20 per Mcf to $8.77 per Mcf in 2006 compared to 2005, which increased gas sales revenues by approximately $2.9 million. As a result of our qualified effective hedging activities, gas sales revenues were higher by $18.7 million ($1.33 per Mcf) in 2006 and lower by $6.6 million ($0.46 per Mcf) in 2005 than if our gas was not hedged. The average price realized for our oil increased from $46.37 per Bbl in 2005 to $62.78 per Bbl in 2006, which increased oil sales revenues by approximately $6.1 million. As a result of our qualified effective hedging activities, oil sales revenues were lower by approximately $2.5 million ($7.00 per Bbl) in 2005 than if our oil was not hedged. Our oil derivatives did not qualify for cash flow hedge accounting following the Transaction and, therefore, did not affect oil sales revenues in 2006. As of July 1, 2006, we determined that our gas derivatives no longer qualified for cash flow hedge accounting. Changes in the fair value of the gas derivatives from that date forward are recorded in derivative fair value gain/loss. Deferred gains or losses on these gas derivatives are recognized as increases or decreases to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings.
The operating margin from oil and gas sales on a per unit basis increased from $6.85 per Mcfe in 2005 to $7.41 per Mcfe in 2006. The average price increased $0.54 per Mcfe and production taxes decreased $0.04 per Mcfe while production expense increased $0.02 per Mcfe in 2006 compared to 2005. Production expense increased approximately $0.02 per Mcfe in 2006 and $0.08 per Mcfe in 2005 due to recording the cost of selling purchased oil inventory as a result of purchase accounting for the Transaction.
The decrease in gas gathering and marketing revenues was due to a $1.3 million decrease in gas marketing revenues and a $349,000 decrease in gas gathering revenues. The lower marketing revenues were primarily the result of lower gas prices. The decrease in gas gathering revenues was primarily due to lower margins on a gathering system in Pennsylvania.
Costs and Expenses
Production expense decreased slightly from $23.2 million in 2005 to $23.1 million in 2006. The average production cost increased from $1.39 per Mcfe in 2005 to $1.41 per Mcfe in 2006 due to lower oil and gas sales volumes in 2006. Production expense increased by $1.3 million ($0.08 per Mcfe) in 2005 and by $385,000 ($0.02 per Mcfe) in 2006 due to recording the cost associated with the selling of purchased oil inventory as a result of purchase accounting for the Transaction. Oil inventory was recorded at fair value of approximately $60.50 per Bbl as of August 16, 2005. Excluding the impact of these oil inventory adjustments, production expense increased by approximately $900,000 (4%) in 2006 compared to 2005. This increase was primarily due to increases in labor and industry service costs.
Production taxes decreased $684,000 from $3.7 million in 2005 to $3.0 million in 2006, primarily due to lower gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging. Average per unit production taxes decreased from $0.22 per Mcfe in 2005 to $0.18 per Mcfe in 2006, primarily due to the decrease in the selling price of natural gas in 2006, excluding the effects of hedging.
Gathering and marketing expense decreased $1.7 million from $11.1 million in 2005 to $9.4 million in 2006 primarily due to lower gas marketing costs as a result of lower gas prices in 2006.
Exploration expense decreased $1.9 million (51%) from $3.7 million in 2005 to $1.8 million in 2006. The decrease was primarily due to decreased compensation-related expenses, partially offset by $1.1 million of non-cash write-offs for expired leases and other costs incurred on unproved properties.
General and administrative expense increased $3.9 million (63%) from 2005 to 2006 primarily due to Council of Petroleum Accountants Societies (“COPAS”) overhead fees paid to EnerVest. We entered into an operating agreement with EnerVest Operating effective October 1, 2005. Under the terms of the agreement, we pay EnerVest Operating a COPAS overhead fee to cover certain production and administrative costs. General and administrative expense includes $642,000 and $5.3 million in COPAS overhead charges from EnerVest Operating in 2005 and 2006, respectively, which offset operating cost reductions following the Transaction.
Depreciation, depletion and amortization increased by $2.9 million from $35.6 million in 2005 to $38.5 million in 2006. This increase was primarily due to an increase in depletion expense. Depletion expense increased $4.1 million (12%) from $33.5 million in 2005 to $37.6 million in 2006 due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $2.01 per Mcfe in 2005 to $2.30 per Mcfe in 2006, primarily due to a higher cost basis resulting from purchase accounting for the Transaction.
Derivative fair value gain/loss was a gain of $37.4 million in 2006 compared to a loss of $13.3 million in 2005. The derivative fair value gain/loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges, the ineffective portion of crude oil swaps through August 15, 2005 and the ineffective portion of natural gas swaps as a result of purchase accounting. Our oil derivatives did not qualify for cash flow hedge accounting following the Transaction and, therefore, changes in fair value have been reflected in derivative fair value gain/loss since the Transaction. As of July 1, 2006, we determined that our gas derivatives no longer qualified for cash flow hedge accounting and, therefore, changes in fair value subsequent to that date are reflected in derivative fair value gain/loss.
Transaction expenses of $7.5 million related to the Transaction were recorded in the Predecessor I Company period ended August 15, 2005. These expenses include severance payments made to employees, unamortized loan costs written off, professional fees and other transaction expenses.
Interest expense decreased $382,000 (2%) from $23.3 million in 2005 to $22.9 million in 2006. This decrease was due to lower blended interest rates which were partially offset by an increase in average outstanding borrowings.
Income tax expense increased from $8.9 million in 2005 to $34.2 million in 2006. The increase in income tax expense was primarily due to an increase in the net income before income taxes in 2006 along with a higher effective tax rate.
2005 Compared to 2004
Revenues
Net operating revenues increased from $112.1 million in 2004 to $154.3 million in 2005. The increase was due to higher gas sales revenues of $36.1 million, higher oil sales revenues of $3.1 million and higher gas gathering and marketing revenues of $3.0 million.
Gas volumes sold decreased 707 Mmcf (5%) from 15.3 Bcf in 2004 to 14.6 Bcf in 2005 resulting in a decrease in gas sales revenues of approximately $4.1 million. Oil volumes sold decreased approximately 23,000 Bbls (6%) from 381,000 Bbls in 2004 to 358,000 Bbls in 2005 resulting in a decrease in oil sales revenues of approximately $800,000. The lower gas sales and oil sales volumes are due to normal production declines partially offset by production from new wells drilled in 2005.
The average price realized for our natural gas increased $2.77 per Mcf to $8.57 per Mcf in 2005 compared to 2004, which increased gas sales revenues by approximately $40.3 million. As a result of our qualified effective hedging activities, gas sales revenues were lower by $6.6 million ($0.46 per Mcf) in 2005 and lower by $9.8 million ($0.64 per Mcf) in 2004 than if our gas was not hedged. The average price realized for our oil increased from $35.47 per Bbl in 2004 to $46.37 per Bbl in 2005, which increased oil sales revenues by approximately $3.9 million. As a result of our qualified effective hedging activities, oil sales revenues were lower by approximately $2.5 million ($7.00 per Bbl) in 2005 and lower by $1.1 million ($2.91 per Bbl) in 2004 than if our oil was not hedged.
The operating margin from oil and gas sales on a per unit basis increased from $4.31 per Mcfe in 2004 to $6.85 per Mcfe in 2005. The average price increased $2.64 per Mcfe which was partially offset by an increase in production expense of $0.04 per Mcfe and an increase in production taxes of $0.06 per Mcfe in 2005 compared to 2004. Production expense increased approximately $0.06 per Mcfe in 2004 and $0.08 per Mcfe in 2005 due to recording the cost of selling purchased oil inventory as a result of purchase accounting for the Merger and the Transaction.
The increase in gas gathering and marketing revenues was due to a $2.1 million increase in gas marketing revenues and a $916,000 increase in gas gathering revenues. The higher marketing revenues were primarily the result of higher gas prices. The increase in gas gathering revenues was primarily due to higher margins on a gathering system in Pennsylvania.
Costs and Expenses
Production expense decreased $599,000 from $23.8 million in 2004 to $23.2 million in 2005. The average production cost increased from $1.35 per Mcfe in 2004 to $1.39 per Mcfe in 2005 due to the higher costs and lower oil and gas sales volumes in 2005. Production expense increased by $975,000 ($0.06 per Mcfe) in 2004 and by $1.3 million ($0.08
per Mcfe) in 2005 due to recording the cost associated with the selling of purchased oil inventory as a result of purchase accounting for the Merger in 2004 and the Transaction in 2005. Oil inventory was recorded at fair value of approximately $31.88 per Bbl as of July 7, 2004 and $60.50 per Bbl as of August 16, 2005. Production expense in 2004 included $1.6 million ($0.09 per Mcfe) of non-cash stock-based compensation expense. Production expense in 2005 was also affected by higher fuel costs and general cost increases.
Production taxes increased $905,000 from $2.8 million in 2004 to $3.7 million in 2005, primarily due to higher oil and gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging. Average per unit production taxes increased from $0.16 per Mcfe in 2004 to $0.22 per Mcfe in 2005, primarily due to the increase in the selling price of natural gas in 2005, excluding the effects of hedging.
Exploration expense decreased $2.3 million (39%) from $6.0 million in 2004 to $3.7 million in 2005 primarily due to decreases in exploratory dry hole expense, expired lease expense and compensation-related expenses. We have decreased exploration activity in order to focus our drilling efforts on lower risk developmental drilling. However, we expect to continue to incur exploration expense for costs related to our ongoing operations, which are classified as exploration expense under the successful efforts method of accounting.
General and administrative expense decreased $363,000 (6%) from 2004 to 2005 primarily due to $1.5 million of non-cash stock-based compensation expense recorded in 2004. This was partially offset by COPAS overhead fees paid to EnerVest in the fourth quarter of 2005. We entered into an operating agreement with EnerVest Operating effective October 1, 2005. Under the terms of the agreement, we will pay EnerVest Operating a COPAS overhead fee to cover certain production and administrative costs. General and administrative expense in 2005 included $642,000 in COPAS overhead charges from EnerVest Operating, which offset operating cost reductions following the Transaction. We expect these overhead charges to result in an increase in general and administrative expense and a decrease in our production expense in the future.
Depreciation, depletion and amortization increased by $9.0 million from $26.6 million in 2004 to $35.6 million in 2005. This increase was primarily due to an increase in depletion expense. Depletion expense increased $9.9 million (42%) from $23.6 million in 2004 to $33.5 million in 2005 due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $1.35 per Mcfe in 2004 to $2.01 per Mcfe in 2005, primarily due to a higher cost basis resulting from purchase accounting for the Transaction on August 16, 2005.
Derivative fair value gain/loss was a loss of $2.4 million in 2004 compared to a loss of $13.3 million in 2005. The derivative fair value gain/loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges, the ineffective portion of crude oil swaps through August 15, 2005 and the ineffective portion of natural gas swaps as a result of purchase accounting.
Transaction expenses of $26.0 million related to the Merger and $7.5 million related to the Transaction were recorded in the Predecessor II Company and Predecessor I Company periods, respectively. These expenses include severance and retention payments made to employees, unamortized loan costs written off, temporary financing facility costs, costs of the consent solicitation process for our $225 million Senior Subordinated Notes due 2007 (the “9-7/8% Notes”) and buyer and seller investment banking fees, professional fees and other transaction expenses.
Interest expense decreased $749,000 (3%) from $24.1 million in 2004 to $23.3 million in 2005. This decrease was due to lower blended interest rates which were partially offset by an increase in average outstanding borrowings.
We had income tax expense of $8.9 million in 2005 compared to an income tax benefit of $3.2 million in 2004. The increase in income tax expense was primarily due to an increase in the net income before income taxes in the 2005 period compared to the 2004 period along with a higher effective tax rate in the 2005 period. The effective tax rate was higher in the 2005 period due to certain nondeductible transaction-related expenses in the 2004 period which reduced the 2004 rate.
Discontinued operations relating to the TBR and Arrow asset sales resulted in a gain, net of tax, of $28.9 million in 2004. This was primarily attributable to the $45.2 million ($28.0 million net of tax) net gain on the sales of the TBR and Arrow recorded in the second quarter of 2004.
Liquidity and Capital Resources
Cash Flows
We expect that our primary sources of cash in 2007 will be from funds generated from operations, from borrowings under the Senior Facilities and from the sale of non-strategic assets. Based on our current level of operations, we believe our cash flow from operations, available cash and available borrowings under our Senior Facilities, will be adequate to meet our future liquidity needs for the foreseeable future. At February 28, 2007, we had approximately $12.6 million available under our revolving facility.
The primary sources of cash in the year ended December 31, 2006 were funds generated from operations and from borrowings under our credit facilities. Funds used during this period were primarily used for operations, exploration and development expenditures, interest expense, and repayment of debt. Our liquidity and capital resources are closely related to and dependent upon the current prices paid for our oil and natural gas.
The following table summarizes the net cash flow for the periods presented:
Our operating activities provided cash flows of $66.6 million during 2006 compared to $91.3 million in 2005. The decrease was primarily due to lower cash received for oil and gas sales, a $4.7 million net decrease in operating assets and liabilities and an increase of $3.9 million in general and administrative expense.
Cash flows used in investing activities were $30.2 million in 2006 compared to cash flows provided by investing activities of $32.5 million in 2005. This decrease was due to a decrease in exploration expense of $2.9 million.
Cash flows used in financing activities in 2006 were $38.6 million compared to $69.0 million in 2005. This decrease was primarily due to a decrease in the settlement of derivative liabilities recorded in purchase accounting of $26.8 million and an increase in debt proceeds of $18.3 million. This was partially offset by an increase in dividends paid of $11.5 million
During 2006, our working capital increased $27.4 million from a deficit of $39.0 million at December 31, 2005 to a deficit of $11.7 million at December 31, 2006. The increase was primarily due to a decrease in the current liability for fair value of derivatives of $37.6 million and a decrease in accrued expenses of $6.9 million. This was offset by a decrease in the deferred income tax asset of $13.1 million and a decrease in accounts receivable of $5.4 million.
Capital Expenditures
The table below sets forth our total capital expenditures for each of the years ending December 31, 2006, 2005 and 2004.
During 2006, we spent approximately $37 million, including exploratory dry hole expense, on our drilling and other capital expenditures. In 2006, we drilled 179 gross (172.3 net) development wells, of which 177 gross (170.3 net) wells were successfully completed as producers in the target formation and 2 gross (2.0 net) wells were dry holes. One exploratory well drilled in 2005 was classified as a dry hole in 2006 and well cost of approximately $82,000 was expensed.
We plan to spend approximately $27 million during 2007 on our drilling activities and other capital expenditures. We intend to finance our planned capital expenditures through our cash on hand, available cash flow, borrowings under our revolving credit facility and, to a lesser extent, the sale of non-strategic assets. At December 31, 2006, and at February 28, 2007, we had approximately $17.1 million and $12.6 million, respectively, available under our revolving facility. The level of our future cash flow will depend on a number of factors including the demand for and price levels of oil and gas, the scope and success of our drilling activities and our ability to acquire additional producing properties. There can be no assurance that the future drilling of our proved undeveloped locations will provide adequate liquidity in the future.
Financing and Credit Facilities
Senior Secured Notes due 2012
We have $159.5 million of our Notes outstanding as of December 31, 2006. As a result of the application of purchase accounting, the notes were recorded as a liability based on the estimated fair value of $200.7 million on the Transaction date. In June 2006, the Company repurchased a portion of the outstanding senior secured notes. The repurchased notes had a face value of $33.025 million and were repurchased at 102.750%. A gain of $436,000 was recorded in 2006 in connection with the transaction. The Notes mature July 15, 2012. Interest is payable semi-annually on January 15 and July 15 of each year at 8.75% based on the face amount of $159.5 million (for an effective rate of 7.946% based on the fair value on the Transaction date.) The Notes are secured on a second-priority lien on the same assets subject to the liens securing our obligations under the Senior Facilities. The Notes are subject to redemption at our option at specific redemption prices.
The Notes are governed by an indenture (the “Indenture”), which contains certain covenants that limit our ability to incur additional indebtedness and issue stock, pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing indebtedness of any kind other than permitted liens and engage in mergers and consolidations.
Amended Credit Agreement
On August 16, 2005, we amended and restated our then existing $170 million credit agreement, by entering into a First Amended and Restated Credit and Guaranty Agreement (“Amended Credit Agreement”) by and among us and BNP Paribas, as sole lead arranger, sole book runner, syndication agent and administrative agent. The Amended Credit Agreement provides for loans and other extensions of credit to be made to us up to a maximum aggregate principal amount of $390 million. The obligations under the Amended Credit Agreement are secured by substantially all of our assets.
The Amended Credit Agreement provides for a revolving credit line in the aggregate principal amount of $350 million and a hedge letter of credit facility in the aggregate principal amount of $40 million. Borrowings under the Amended Credit Agreement may not exceed the borrowing base, which was initially set at $80.25 million, of which $57 million was drawn at closing on August 16, 2005. At December 31, 2006, the borrowing base was $113.4 million and the outstanding balance was $95.4 million. This agreement was amended on September 27, 2005 to reduce the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 70%. J.P. Morgan Chase and Amegy Bank became members of the bank group in September 2005.
Borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate or an adjusted federal funds rate, plus an applicable margin ranging from 0% to 0.625% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at the Company’s option, the Eurodollar base rate plus an applicable margin ranging from 1.125% to 2.125% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2010.
The obligations under the Amended Credit Agreement are secured by a first lien security interest in substantially all of our assets. The obligations under the Amended Credit Agreement are further secured by a pledge of 100% of our capital stock held by Capital C, our parent.
The Amended Credit Agreement contains covenants that will limit our ability to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase our stock; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber our capital stock; or enter into transactions with affiliates. The Amended Credit Agreement also requires compliance with customary financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a minimum current ratio. As of December 31, 2006, we were in compliance with all financial covenants and requirements under the existing credit facilities.
Borrowings under the revolving credit line will be used by us for general corporate purposes. In accordance with the terms of the Amended Credit Agreement, letters of credit issued under the hedge letter of credit commitment and any related borrowings are to be used solely to secure payment of our obligations under the J. Aron Swap (defined hereinafter).
In connection with our entry into the Amended Credit Agreement, we executed a Subordinated Promissory Note (“Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Note, Capital C loaned $25 million to us on August 16, 2005. The Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the Note made on August 16, 2005. Interest payments on the Note are due quarterly commencing September 30, 2005. In lieu of cash payments, we have the option to make interest payments on the Note by borrowing additional amounts against the Note. The interest payments in 2005 and 2006 were paid in cash. The Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. The Note is expressly subordinate to our senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap and notes issued under our Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee (“Senior Secured Notes”).
ISDA Master Agreement
In connection with the Transaction, we amended and restated the Schedule and Credit Support Annex to our International Swap Dealers Association (“ISDA”) Master Agreement, dated as of June 30, 2004, by and between us and J. Aron & Company (“J. Aron Swap”), pursuant to which we have agreed, from time to time, to enter into cash-settled hedge transactions with J. Aron & Company, as hedge counterparty, in connection with various gas and oil commodity derivatives transactions. The amendments to the J. Aron
Swap conform the terms of the Schedule and Credit Support Annex to the terms of the Amended Credit Agreement, change certain covenants and reduce the maximum amount of the letter of credit securing the hedge obligations from $55 million to $40 million.
From time to time we may enter into interest rate swaps to hedge the interest rate exposure associated with the credit facility, whereby a portion of our floating rate exposure is exchanged for a fixed interest rate. At December 31, 2005 and 2006, we had interest rate swaps in place covering $40 million and $80 million, respectively, of our outstanding debt under the revolving credit facility that mature on September 16, 2008. There were no interest rate swaps in 2004.
At December 31, 2006, the aggregate long-term debt maturing in the next five years is as follows: $7,000 (2007); $8,000 (2008); $8,000 (2009); $95.4 million (2010) and $184.5 million (2011 and thereafter).
Derivative Instruments
The Hedges
To manage our exposure to natural gas or oil price volatility, we may partially hedge our physical gas or oil sales prices by selling futures contracts on the NYMEX or by selling NYMEX-based commodity derivative contracts which are placed with major financial institutions that we believe are minimal credit risks. The contracts may take the form of futures contracts, swaps, collars or options.
On July 7, 2004, the date of the Merger, we became a party to long-term commodity hedges (the “Hedges”) with J. Aron pursuant to a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”.) We anticipate that the Hedges will cover approximately 63% of the expected 2006 through 2013 production from our current estimated proved reserves and will range from 58% to 71% of such expected production in any year. The Hedges primarily take the form of monthly settled fixed price swaps in respect of the settlement prices for the market standard NYMEX futures contracts on crude oil and natural gas. Under such transactions, we pay NYMEX-based floating price per Mmbtu, in the case of Hedges on natural gas, and we pay a NYMEX-based floating price per Bbl, in the case of Hedges on crude oil, for each month during the term of the Hedges and receive a fixed price per Mmbtu or Bbl (as the case may be) according to a monthly schedule of fixed prices that we established upon completion of the Merger. The transactions will be settled on a net basis. The notional amounts of the Hedges were designed to provide sufficient hedged cash flow to cover operating expenditures, general and administrative expenses, interest expenses and the majority of capital expenditures needed to develop proved reserves.
We are required to cause the Hedge Agreement to remain in effect for so long as any portion of the Notes remains outstanding. The Hedges are documented under a standard ISDA agreement with customized credit terms, designed to mitigate the liquidity pressures in a high commodity price environment. The initial collateral requirements and ongoing margin requirements (based on market movements) are satisfied by letters of credit issued under the Senior Facilities, with an aggregate capitalization of $40 million. To support any exposure in excess of amounts supported by the letters of credit, we have granted J. Aron a second lien on the same assets that secure the Senior Facilities and the Notes and, to the extent our obligations exceed such letters of credit, such obligations are secured by a second-priority lien on the same assets securing the Senior Facilities and the Notes and are guaranteed by the same subsidiaries that guarantee the Senior Facilities and the Notes on a second-priority senior secured basis. We may enter into crude oil and natural gas hedges with parties other than J. Aron, which hedges may be secured by the letters of credit issued under the Senior Facilities and by a second-priority lien on the same assets securing the Senior Facilities and the Notes.
In March 2003, we entered into a collar for 4,320 Bbtu of our natural gas production in 2004 with a ceiling price of $5.80 per Mmbtu and a floor price of $4.00 per Mmbtu. We also sold a floor at $3.00 per Mmbtu on this volume of gas. This aggregate structure has the effect of: 1) setting a maximum price of $5.80 per Mmbtu; 2) floating at prices from $4.00 to $5.80 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.00 and $4.00 per Mmbtu; and 4) receiving a price of $1.00 per Mmbtu above the price if the price is $3.00 or less. All prices are based on monthly NYMEX settle. Upon the Merger, these contracts were transferred to J. Aron and re-established at a ceiling price of $5.75. These contracts were settled during 2004.
In April 2003, we entered into a collar for 6,000 Bbtu of our natural gas production in 2005 with a ceiling price of $5.37 per Mmbtu and a floor price of $4.00 per Mmbtu. We also sold a floor at $3.10 per Mmbtu on this volume of gas. This aggregate structure has the effect of: 1) setting a maximum price of $5.37 per Mmbtu; 2) floating at prices from $4.00
to $5.37 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.10 and $4.00 per Mmbtu; and 4) receiving a price of $0.90 per Mmbtu above the price if the price is $3.10 or less. All prices are based on monthly NYMEX settle. Upon the Merger, these contracts were transferred to J. Aron and re-established at a ceiling price of $5.32. These contracts were settled during 2005.
Our financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. Accordingly, we may modify our fixed price contract and financial derivative positions by entering into new transactions. The following tables reflect the natural gas and crude oil volumes and the weighted average prices under financial derivatives (including settled contracts) at December 31, 2006. We have not entered into any additional derivative transactions since December 31, 2006.
Mcf - Thousand cubic feet
Mmbtu - Million British thermal units
Bbl - Barrel
Mmcf - Million cubic feet
Bbtu - Billion British thermal units
Mbbls - Thousand barrels
At December 31, 2006, the fair value of futures contracts covering 2007 through 2013 oil and gas production represented an unrealized loss of $187.5 million. Commodity prices have increased since December 31, 2006 and, as a result, the fair value of our oil and gas derivatives as of February 28, 2007 was an unrealized loss of approximately $209.4 million.
At December 31, 2006, we had interest rate swaps in place on $80 million of our outstanding debt under the revolving credit facility through September 16, 2008. The swaps provide a 1-month LIBOR fixed rates at 4.285% on $40 million and 5.160% on $40 million, plus the applicable margin. At December 31, 2006, the fair value of the interest rate swaps represented an unrealized gain of $481,000.
Inflation and Changes in Prices
The average price realized for our natural gas increased from $5.80 per Mcf in 2004 to $8.57 per Mcf in 2005, and increased to $8.77 in 2006. The average price realized for our oil increased from $35.47 per Bbl in 2004 to $46.37 per Bbl in 2005 and increased to $62.78 per Bbl in 2006. These prices reflect average prices for oil and gas sales of our continuing operations. The prices include the effect of our qualified effective oil and gas hedging activity.
The price of oil and natural gas has a significant impact on our results of operations. Oil and natural gas prices fluctuate based on market conditions and, accordingly, cannot be predicted. Costs to drill, complete and service wells can fluctuate based on demand for these services which is generally influenced by high or low commodity prices. Our costs and expenses may be subject to inflationary pressures if oil and gas prices are favorable.
A large portion of our natural gas is sold subject to market sensitive contracts. Natural gas price risk is mitigated (hedged) by the utilization of over-the-counter NYMEX swaps, options or collars. Natural gas price hedging decisions are made in the context of our strategic objectives, taking into account the changing fundamentals of the natural gas marketplace.
Contractual Obligations
We have various commitments primarily related to leases for office space, vehicles, natural gas compressors and computer equipment. We expect to fund these commitments with cash generated from operations.
The following table summarizes our contractual obligations at December 31, 2006.
In addition to the items above, we have entered into joint operating agreements, area of mutual interest agreements and joint venture agreements with other companies. These agreements may include drilling commitments or other obligations in the normal course of business.
The following table summarizes our commercial commitments at December 31, 2006.
In the normal course of business, we have performance obligations which are supported by surety bonds or letters of credit. These obligations are primarily site restoration and dismantlement, royalty payments and exploration programs where governmental organizations require such support. We also have letters of credit with our hedging counterparty.
Off-Balance Sheet Arrangements
We have $40.9 million in letters of credit as described above.
NEW ACCOUNTING STANDARDS
In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, Accounting for Certain Hybrid Instruments, to simplify and make more consistent the accounting for certain financial instruments. SFAS No. 155 amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to permit fair value remeasurement for any hybrid financial instrument with an embedded derivative that would otherwise require bifurcation, provided that the whole instrument is accounted for on a fair value basis. SFAS No. 155 also amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, to allow a qualifying special purpose entity to hold a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We adopted SFAS No. 155 on January 1, 2007, and there was no impact on our consolidated financial statements.
In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement 109” (“FIN 48”), which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is “more-likely-than-not” to be sustained if the position were to be challenged by a taxing authority. The assessment of the tax position is based solely on the technical merits of the position, without regard to the likelihood that the tax position may be
challenged. If an uncertain tax position meets the “more-likely-than-not” threshold, the largest amount of tax benefit that is more than 50 percent likely to be recognized upon ultimate settlement with the taxing authority, is recorded. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. Consistent with the requirements of FIN 48, we adopted FIN 48 on January 1, 2007. We are currently evaluating the impact of adopting FIN 48 and do not expect the interpretation will have a material impact on our consolidated financial statements.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 establishes a fair value hierarchy and clarifies the principle that fair value should be based on assumptions market participants would use when pricing the asset or liability. SFAS No. 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We will adopt SFAS No. 157 on January 1, 2008, and we do not expect the adoption to have a material impact on our consolidated financial statements.
In September 2006, the SEC issued Staff Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. SAB 108 addresses how the effects of prior year uncorrected misstatements should be considered when quantifying misstatements in current year financial statements. SAB 108 requires companies to quantify misstatements using a balance sheet and income statement approach and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. We adopted SAB 108 on December 31, 2006, and there was no impact on our consolidated financial statements.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been selected are reported in earnings. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We will adopt SFAS No. 159 on January 1, 2008, and we have not yet determined the impact, if any, on our consolidated financial statements.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Among other risks, we are exposed to interest rate and commodity price risks.
The interest rate risk relates to existing debt under our revolving credit facility as well as any new debt financing needed to fund capital requirements. We may manage our interest rate risk through the use of interest rate swaps to hedge the interest rate exposure associated with the credit agreement, whereby a portion of our floating rate exposure is exchanged for a fixed interest rate. A portion of our long-term debt consists of senior secured notes where the interest component is fixed. At December 31, 2006, we had interest rate swaps in place covering $80 million of our outstanding balance on the revolving credit facility. These swaps provide us with a 1-month LIBOR fixed interest rates of 4.285% on $40 million and 5.160% on $40 million, plus the applicable margin, until September 16, 2008. If market interest rates for short-term borrowings increased 1%, the increase in our annual interest expense would be approximately $154,000. This sensitivity analysis is based on our financial structure at December 31, 2006.
The commodity price risk relates to our natural gas and crude oil produced, held in storage and marketed. Our financial results can be significantly impacted as commodity prices fluctuate widely in response to changing market forces. From time to time we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to commodity price volatility. The fixed-price physical contracts generally have terms of a year or more. We employ a policy of hedging oil and gas production by selling NYMEX-based commodity derivative contracts which are placed with major financial institutions that we believe are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. At December 31, 2006, we had derivatives covering a portion of our oil and gas production from 2007 through 2013. Our oil and gas sales revenues included a net pre-tax loss of $9.1 million in 2005 and a net pre-tax gain of $18.7 million in 2006 on our qualified hedging activities.
We determined that as of August 15, 2005, our oil derivatives no longer qualify for cash flow hedge accounting and as of July 1, 2006, our gas derivatives no longer qualify for cash flow hedge accounting. From those dates forward, changes in the fair value of the oil and gas derivatives are recorded in derivative fair value gain/loss. Deferred gains or losses on the gas derivatives are recognized as increases or decreases to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings. If gas prices decreased $0.75 per Mcf, our gas sales revenues would decrease by approximately $10.6 million. If the price of crude oil decreased $6.00 per Bbl, our oil sales revenues would decrease by approximately $2.2 million. The impact of these price decreases on our cash flows would be significantly less than these amounts due to our oil and gas derivatives. Price decreases of $0.75 per Mcf and $6.00 per Bbl would decrease cash flows from the sale of oil and gas by approximately $3.4 million after considering the effects of the derivative contracts in place as of December 31, 2006. This sensitivity analysis is based on our 2006 oil and gas sales volumes.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Index to Consolidated Financial Statements and Schedules on page sets forth the financial statements included in this Annual Report on Form 10-K and their location herein. Schedules have been omitted as not required or not applicable because the information required to be presented is included in the financial statements and related notes.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
On November 2, 2005, we dismissed Ernst & Young LLP (“Ernst & Young”) as our independent registered public accounting firm. Our full Board of Directors, also functioning as our Audit Committee, approved the dismissal of Ernst & Young.
Ernst & Young’s report on our financial statements for the fiscal year ended December 31, 2004 contained no adverse opinion or disclaimer of opinion and was not qualified or modified as to uncertainty, audit scope or accounting principle.
During the year ended December 31, 2004 and through November 2, 2005, there were no disagreements with Ernst & Young on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreement(s), if not resolved to the satisfaction of Ernst & Young, would have caused Ernst & Young to make reference to the subject matter of the disagreement(s) in Ernst & Young’s reports.
During the year ended December 31, 2004 and through November 2, 2005, there were no “reportable events,” as defined in Item 304(a)(1)(v) of Regulation S-K.
Effective November 2, 2005, our Board of Directors, also functioning as our Audit Committee, appointed Deloitte & Touche LLP (“Deloitte & Touche”) as our independent registered public accounting firm. Deloitte & Touche was not consulted by us on any matter described in Item 304(a)(2) of Regulation S-K during the year ended December 31, 2004 or through November 2, 2005 (the date Deloitte & Touche was engaged).
Item 9A.
Item 9A. CONTROLS AND PROCEDURES
Material Weakness Previously Disclosed
As discussed in our 2004 Annual Report on Form 10-K, as amended, we did not maintain effective disclosure controls as of December 21, 2004 to ensure that hedge accounting was correctly applied pursuant to generally accepted accounting principles. The remedial actions implemented in the fourth quarter of 2005 and the first quarter of 2006 related to these material weaknesses are described below.
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2006. As discussed below, we have made various changes in our internal controls which we believe remediate the material weaknesses previously identified by the company. We are relying on those changes in internal controls as an integral part of our disclosure controls and procedures.
Based upon the results of the evaluation of our disclosure controls and procedures and based upon our reliance on these revised internal controls, management, including our Chief Executive Officer and our Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of December 31, 2006.
Changes in Internal Control over Financial Reporting
During the fourth quarter of 2005 and the first quarter of 2006, we implemented the following changes in our internal control over financial reporting:
•
Revised our accounting procedures for derivative accounting by correcting how we calculate our journal entries related to derivative instruments and hedge accounting.
•
Implemented a reconciliation calculation for our hedges to help ensure proper financial statement recognition of hedge accounts.
•
Engaged a consulting firm to assist us in reviewing our approach to derivative instruments and hedge accounting.
Except as described above, there were no changes in the internal control over financial reporting that occurred during the year ended December 31, 2006 that materially affected, or that are reasonably likely to materially affect, internal control over financial reporting.
Item 9B.
Item 9B. OTHER INFORMATION
Not applicable.
PART III
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE
Our executive officers and directors and their respective positions and ages of as of March 5, 2007 were as follows:
All of our executive officers serve at the pleasure of our Board of Directors. None of our executive officers is related to any other executive officer or director. The Board of Directors consists of four members, the business experience of each executive officer and director is summarized below.
Mark A. Houser. On August 16, 2005, Mr. Houser was appointed our Chief Executive Officer and Chairman of the Board of Directors. Mr. Houser is Executive Vice President and Chief Operating Officer of EnerVest Management Partners, Ltd. and President, Chief Operating Officer and Director of EV Management, LLC, the general Partner of EV Energy Partners, L.P. Prior to that, Mr. Houser was Vice President, United States Exploration and Production, for Occidental Petroleum Corporation, or Oxy, where he helped lead Oxy’s reorganization of its domestic reserve base. Mr. Houser began his career as an engineer with Kerr-McGee Corporation. He holds a petroleum engineering degree from Texas A&M University and an MBA from Southern Methodist University.
James M. Vanderhider. Mr. Vanderhider is our President and Chief Financial Officer. Prior to that he served as President and Chief Operating Officer since his appointment on August 16, 2005. Mr. Vanderhider has been a director since August 16, 2005. He also serves as Executive Vice President and Chief Financial Officer of EnerVest and has been with EnerVest since March 1996. Prior to joining EnerVest, Mr. Vanderhider was Executive Vice President and Chief Financial Officer of Torch Energy and Senior Vice President and Chief Financial Officer of Nuevo Energy. Prior to such time, Mr. Vanderhider was a management member of the Internal Audit department of The Coastal Corporation, now a subsidiary of El Paso Corporation. He also held the position of Chief Financial Officer of Walker Energy Partners, a master limited partnership which he helped form. Mr. Vanderhider began his career with Deloitte and Touche in the audit department focusing on the energy industry.
Mr. Vanderhider received a B.B.A. degree in Accounting from Texas A&M University where he graduated summa cum laude. He is a Certified Public Accountant. Mr. Vanderhider is a native Houstonian and is actively involved with several industry and social organizations. He is a member of the Independent Petroleum Association of America, the American Institute of Certified Public Accountants, Houston Producers’ Forum, Texas Society of Certified Public Accountants, Houston Energy Finance Group, and Houston Acquisitions and Divestitures Organization. He serves on the Board of Trustees of Goodwill Industries of Houston and on the Board of Directors of the Houston Center Club, a social and athletic club.
Kenneth Mariani. On October 3, 2005, Mr. Mariani was appointed Senior Vice President and Chief Operating Officer. He has been a director since August 16, 2005. Mr. Mariani is also Senior Vice President, Eastern Division, for EnerVest and Executive Vice President of CGAS Exploration, Inc., a privately-held oil and gas company owned by certain institutional funds managed by EnerVest. Prior to joining EnerVest in 2000, he served as Vice President of Operations for Energy Corporation of America.
Mr. Mariani holds a degree in Chemical Engineering from the University of Pittsburgh, graduating cum laude with a Petroleum option. He received his MBA degree from the University of Texas and is a Certified Professional Engineer. Mr. Mariani is an active member of the Independent Oil and Gas Association of West Virginia, recently serving on the Board of Directors, Commerce Committee and Safety Committee. In 2003, he was acting Vice President and Program Chair of this organization. He is past Chairman of the Society of Petroleum Engineers and a member of IPAA. Currently, Mr. Mariani serves on the Board of Directors for the Michigan Oil and Gas Association and the Ohio Oil and Gas Association. He is also active in the Independent Oil and Gas Association of Pennsylvania, the Independent Oil and Gas Association of New York and the Kentucky Oil and Gas Association.
Frederick J. Stair. Mr. Stair is Vice President of Accounting and has been our Vice President since January 2003. He previously served as our Corporate Controller from 1997 to 2005 and as Controller of the Exploration and Production Division from 1991 to 1997. Mr. Stair joined us in 1981 and has 25 years of accounting experience in the oil and gas industry. Mr. Stair is also Vice President of Accounting - Eastern Division for EnerVest. He graduated from the University of Akron where he received a Bachelor of Science degree in Accounting. Mr. Stair is a member of the Council of Petroleum Accountants Societies of Appalachia.
Barry K. Lay. Mr. Lay was appointed Vice President of Land and Secretary on October 16, 2006. He previously served as Vice President and General Manager of our Pennsylvania/New York District. Prior to joining us in 2002, Mr. Lay was Vice President of Engineering for Waco Oil and Gas Company. He also serves as Vice President of Operations - Eastern Division for EnerVest.
Mr. Lay has 30 years of experience in the oil and gas industry. Mr. Lay graduated from West Virginia University with a Bachelor of Science degree in Petroleum Engineering. He serves as Chairman for numerous State oil and gas regulatory boards including the West Virginia Oil and Gas Conservation Commission, West Virginia Coal Bed Methane Review Board and the West Virginia Shallow Gas Well Review Board. Mr. Lay is a registered Professional Engineer and a licensed Land Surveyor in the State of West Virginia.
David M. Elkin. Mr. Elkin was appointed Vice President of Engineering on October 16, 2006. He also serves as Vice President of Engineering - Eastern Division for EnerVest. Mr. Elkin joined EnerVest in 2003. He holds a Bachelor of Science in Petroleum and Natural Gas Engineering from The Pennsylvania State University. Prior to joining EnerVest, Mr. Elkin was employed for 17 years with Energy Corporation of America, rising to the position of Vice President of Operations. Mr. Elkin is a member of the Independent Oil and Gas Associations in West Virginia, Pennsylvania, New York, Ohio, Kentucky and Michigan. He is also a member and past officer of the Society of Petroleum Engineers. Mr. Elkin has drilled and operated production in the Appalachian, Michigan, and Powder River basins of North America, as well as the Wairoa basin of New Zealand.
Mark L. Barnhill. Mr. Barnhill was appointed Vice President of Exploration on October 16, 2006. He also serves as Vice President of Exploration for EnerVest. Mr. Barnhill joined EnerVest in 2001. Prior to joining EnerVest, he was Exploration Manager for Energy Corporation of America. Mr. Barnhill has worked as both a geologist and a geophysicist for Texaco, Inc. and Cotton Petroleum. He holds a Bachelor of Science degree in Geology from Wright State University, a Master of Science in Geology from The University of Tulsa, and a Ph.D. in Geology from The University of Cincinnati.
Mr. Barnhill was a Visiting Research Scientist at Indiana University/Indiana Geological Survey from 1991 to 1994 where he headed several research projects for the Department of the Navy. He is a member of the American Association of Petroleum Geologists, the Independent Oil and Gas Association of West Virginia, the Independent Oil and Gas Association of Pennsylvania, the Ohio Oil and Gas Association and the Michigan Oil and Gas Association. Mr. Barnhill has given numerous talks at major association meetings both nationally and internationally.
Matthew Coeny. On August 16, 2005, Mr. Coeny was elected to our Board of Directors. Mr. Coeny is a Director of Citigroup Private Equity (“CPE”). CPE is a business unit of Citigroup Inc. (“Citigroup”) and is responsible for private equity
investments, mezzanine debt investments and private equity partnership commitments on behalf of Citigroup affiliates and clients. Since joining CPE in 2000, he has participated in the evaluation, due diligence and execution of investments in a variety of industries. Prior to joining CPE, Mr. Coeny worked in Citigroup’s Investment Banking Division where he participated in numerous advisory and capital raising transactions. Prior to joining Citigroup in 1996, he was a Senior Consultant in KPMG’s Corporate Transactions practice. Mr. Coeny received a Bachelor of Science degree in Finance and Accounting from New York University.
Audit Committee
Our full Board of Directors serves as our Audit Committee.
Code of Ethics
We have adopted a Code of Ethics that applies to our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Vice President of Accounting and any person performing similar functions. It is available without charge upon oral or written request, by contacting:
Belden & Blake Corporation
1001 Fannin Street, Suite 800
Houston, Texas 77002
Attention: Barry Lay, Secretary
Telephone: (713) 659-3500
Item 11.
Item 11. EXECUTIVE COMPENSATION
All of our executive officers are full-time employees of EnerVest and its subsidiaries. We have entered into an operating agreement with a subsidiary of EnerVest (described in Item 13). Pursuant to the operating agreement, we pay EnerVest a fee to operate our business, and EnerVest provides us the services of its employees, including our executive officers, to operate our business. The fee we pay to EnerVest does not include any direct reimbursement for the salaries, bonuses or other compensation paid by EnerVest to the EnerVest employees which act as our executive officers. Therefore, no executive officers of Belden & Blake received any remuneration from Belden & Blake Corporation during 2006.
Compensation of Directors
Our directors are not compensated. We have no independent directors, as independence is defind by the New York Stock Exchange.
Compensation Committee Interlocks and Insider Participation
We do not have a compensation committee. As of December 31, 2006, none of our officers are compensated by us.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
The following table sets forth certain information as of March 5, 2007 regarding the beneficial ownership of our common stock by each person who beneficially owns more than five percent of our outstanding common stock, each director, the Chief Executive Officer and the four other most highly compensated executive officers and by all of our directors and executive officers, as a group:
(1)
Subsidiaries of EnerVest Management Partners, Ltd., are the general partners of the limited partnership that owns Capital C Energy Operations, L.P. EnerVest, therefore, also may be deemed to be a beneficial owner of the 1,534 shares (100%) of our Common Stock. The address of EnerVest Management Partners, Ltd., is 1001 Fannin Street, Suite 800, Houston, Texas 77002. EnerVest is a Texas limited partnership. Messrs. John B. Walker, Jon Rex Jones and A.V. Jones by virtue of their direct and indirect ownership of the limited liability company that acts as EnerVest’s general partner, may be deemed to beneficially own the Common Stock beneficially owned by EnerVest. Messrs. Walker, John Rex Jones and A.V. Jones disclaim beneficial ownership of such Common Stock. The addresses for Messrs. Walker, Jon Rex Jones and A.V. Jones are the same as for EnerVest.
Equity Compensation Plan Information:
We have a 1997 non-qualified stock option plan under which we are authorized to issue up to 1,466 shares of common stock to officers and employees. No options were granted during 2005 or 2006 and as of December 31, 2006, no options were outstanding under the plan. We have no intentions to grant any options under the plan.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
On August 16, 2005, the former partners of Capital C completed the sale of all of the partnership interests in Capital C to certain institutional funds managed by EnerVest Management Partners, Ltd. (“EnerVest”). EnerVest incurred and was reimbursed by us $1.1 million for transaction costs. This amount was recorded as an accrued expense at December 31, 2005 and was paid in January 2006.
On March 15, 2006, we entered into a joint operating agreement with EnerVest Operating L.L.C. (“EnerVest Operating”), a subsidiary of EnerVest. The joint operating agreement was effective October 1, 2005 and resulted in expense to us of $642,000 in 2005 and $5.3 million in 2006 for overhead fees. We also paid $6.7 million for field labor, vehicles and district office expense, $875,000 for drilling overhead fees and $1.3 million for drilling labor costs in 2006 related to this agreement. We reimbursed EnerVest Operating for expenses of $332,000 in 2006 related to the transition of accounting responsibilities to EnerVest Operating’s Charleston, West Virginia office.
The Company paid approximately $211,000 to Opportune LLP in 2006 for consulting services related to the Company’s amended filings and the 2005 Form 10-K. John Vanderhider, brother of James Vanderhider, the Company’s President and Chief Financial Officer, is a partner with Opportune.
The Company paid approximately $207,000 to PetroAcct LP in 2006 for services related to the transition of accounting and information system responsibilities from the Company to EnerVest Operating. A subsidiary of EnerVest Management Partners, Ltd owned 50% of PetroAcct during 2006. The 50% ownership interest in PetroAcct was sold to Opportune in March 2007.
As of December 31, 2006, we owed EnerVest Operating $1,243,000 and EnerVest owed us $520,000.
In connection with the Transaction, we executed a subordinated promissory note in favor of our parent, Capital C in the maximum amount of $94 million. Under the note, Capital C loaned $25 million to us on August 16, 2005 in connection with the Transaction. The note accrues interest at 10% per year and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the note made on August 16, 2005. Interest payments on the note are due quarterly commencing September 30, 2005. In lieu of cash payments, we have the option to make interest payments on the note by borrowing additional amounts against the note. The amount due under the note at December 31, 2006 was $25 million. We made cash payments of $945,000 in 2005 and $2.5 million in 2006.
Messrs. Houser, Vanderhider and Mariani are officers and directors of the Company and they are officers and equity owners of EnerVest. The institutional funds that are managed by EnerVest and own our direct parent, Capital C, also hold other investments in oil and gas assets and operations. We can give no assurance that conflicts of interest will not arise for corporate opportunities. Also, we can give no assurance that conflicts will not arise with respect to the time and attention devoted to us by Messrs. Houser, Vanderhider and Mariani.
Item 14.
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Deloitte & Touche served as our independent auditor for the years ended December 31, 2006 and 2005. On November 2, 2005, the Board replaced Ernst & Young with Deloitte & Touche as our independent auditor. Aggregate fees for professional services provided to us by Ernst & Young and Deloitte & Touche for the years ended December 31, 2006 and 2005 were as follows:
Fees for audit services include fees associated with the annual audit, the review of our Annual Report on Form 10-K and the reviews of our Quarterly Reports on Form 10-Q. Tax fees included tax compliance and tax planning. All other fees include research materials. Our Audit Committee approved 100% of these accounting services.
Audit Committee Pre-Approval Policies and Procedures
The Audit Committee has adopted a policy that requires advance approval of all audit, audit-related, and other services performed by the independent auditor or other public accounting firms. The policy provides for pre-approval by the Audit Committee of specifically defined audit and non-audit services. Unless the specific service has been previously pre-approved with respect to that year, the Audit Committee must approve the permitted service before the independent auditor or public accounting firm is engaged to perform it. The Audit Committee has delegated to the Chairman of the Audit Committee authority to approve permitted services up to $75,000 per year provided that the Chairman reports any decisions to the Committee at its next scheduled meeting. All services of $75,000 or more are required to be approved by a majority of the Committee members.
PART IV
Item 15.
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Documents filed as a part of this report:
1. Financial Statements
The financial statements listed in the accompanying Index to Consolidated Financial Statements and Schedules are filed as part of this Annual Report on Form 10-K.
2. Financial Statement Schedules
No financial statement schedules are required to be filed as part of this Annual Report on Form 10-K.
3. Exhibits
(c) Exhibits required by Item 601 of Regulation S-K
Exhibits required to be filed by the Company pursuant to Item 601 of Regulation S-K are contained in the Exhibits listed under Item 15(a)3.
(d) Financial Statement Schedules required by Regulation S-X
The items listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K.
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.
BELDEN & BLAKE CORPORATION
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.
BELDEN & BLAKE CORPORATION
INDEX TO CONSOLIDATED
FINANCIAL STATEMENTS AND SCHEDULES
Item 15(a) (1) and (2)
All financial statement schedules have been omitted since the required information is not present in amounts sufficient to require submission of the schedule or because the information required is included in the financial statements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Owners of
Belden & Blake Corporation
Houston, Texas
We have audited the accompanying consolidated balance sheets of Belden & Blake Corporation subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, changes in shareholders’ equity (deficit), and cash flows for the year ended December 31, 2006, for the one hundred thirty-eight day period from August 16, 2005 to December 31, 2005 (Successor Company) and for the two hundred twenty-seven day period from January 1, 2005 to August 15, 2005 (Predecessor I Company). 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2006 and 2005, and the results of its operations and its cash flows for the year ended December 31, 2006, for the one hundred thirty-eight day period from August 15, 2005 to December 31, 2005 (Successor Company) and for the two hundred twenty-seven day period from January 1, 2005 to August 15, 2005 (Predecessor I Company), in conformity with accounting principles generally accepted in the United States of America.
DELOITTE & TOUCHE LLP
Houston, Texas
March 31, 2007
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholder and Board of Directors
Belden & Blake Corporation
We have audited the accompanying consolidated statements of operations, shareholders’ equity (deficit), and cash flows for the one hundred seventy-eight day period ended December 31, 2004 and the one hundred eighty-eight day period ended July 6, 2004 of Belden & Blake Corporation (Company). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule 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 the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows for the one hundred seventy-eight day period ended December 31, 2004 and the one hundred eighty-eight day period ended July 6, 2004 of Belden & Blake Corporation, in conformity with U.S. generally accepted accounting principles.
ERNST & YOUNG LLP
Cleveland, Ohio
February 11, 2006
BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
See accompanying notes.
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
See accompanying notes.
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (DEFICIT)
(in thousands)
See accompanying notes.
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
See accompanying notes.
BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Transaction and Merger
Unless the context requires otherwise or unless otherwise noted, when we use the terms “Belden & Blake,” “we,” “us,” “our” or the “Company,” we are referring to Belden & Blake Corporation. On August 16, 2005, the former partners of the direct parent of Belden & Blake Corporation (the “Company”), Capital C Energy Operations, L.P., a Delaware limited partnership (“Capital C”), completed the sale of all of the partnership interests in Capital C to certain institutional funds managed by EnerVest Management Partners, Ltd. (“EnerVest”), a Houston-based privately held oil and gas operator and institutional funds manager (the “Transaction”). The Transaction resulted in a change in control of the Company (“Change in Control”).
On July 7, 2004, the Company, Capital C and Capital C Ohio, Inc., an Ohio corporation and a wholly owned subsidiary of Capital C (“Merger Sub”), completed a merger pursuant to which Merger Sub was merged with and into the Company (the “Merger”), with the Company surviving the Merger as a wholly owned subsidiary of Capital C. The Merger resulted in a change in control of the Company. The general partner of Capital C was controlled by Carlyle/Riverstone Global Energy and Power Fund II, L.P. and Capital C Energy Partners, L.P. until the Transaction on August 16, 2005.
The Transaction and Merger were each accounted for as a purchase effective August 16, 2005 and July 7, 2004, respectively. The Transaction and Merger resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at that date. Accordingly, the financial statements for the period subsequent to August 15, 2005 are presented on the Company’s new basis of accounting, while the results of operations for prior periods reflect the historical results of the two predecessor companies. Vertical black lines are presented to separate the financial statements of the two predecessor companies and the successor company. The “Successor Company” refers to the period from August 16, 2005 and forward. The “Predecessor I Company” refers to the period from July 7, 2004 through August 15, 2005. The “Predecessor II Company” refers to the period prior to July 7, 2004.
The aggregate value of the total equity consideration paid for the Transaction was $125 million, which includes $116 million paid to former shareholders and a $9 million equity contribution. The table below summarizes the allocation of the Transaction’s purchase price based on the acquisition date fair values of the assets acquired and the liabilities assumed.
Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in the acquisition. The recorded goodwill is not deductible for tax purposes.
The principal factors that contributed to the purchase price that resulted in goodwill are as follows:
•
Cost savings and operational synergies of the Company when combined with the other operations managed by EnerVest. These savings include the elimination of duplicative facilities, reduction of personnel and operating and development costs through the management of a larger asset base.
•
The affiliation with EnerVest, an acquisition-focused company, coupled with the enhanced presence in the Appalachian and Michigan basins with EnerVest’s other operations, provides the opportunity to create value by highgrading investment opportunities and identifying new investment opportunities.
•
The going-concern value of the Company, including its experienced workforce.
•
A deferred tax liability was recorded to recognize the difference between the historical tax basis of the assets and the acquisition costs recorded for book purposes. Goodwill was recorded to recognize this tax basis differential.
SFAS No. 142, Goodwill and Other Intangible Assets requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change could potentially result in an impairment.
The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. As the Company has only one reporting unit the reporting unit used for testing will be the entire company. The fair value of the reporting unit is determined and compared to the book value of that reporting unit. If the fair value of the reporting unit is less than the book value (including goodwill) then goodwill is reduced to its fair value and the amount of the writedown is charged to earnings.
The fair value of the reporting unit will be based on estimates of future net cash flows from proved reserves and from future exploration for and development of unproved reserves. Downward revisions of estimated reserves or production, increases in estimated future costs or decreases in oil and gas prices could lead to an impairment of all or a portion of goodwill in future periods.
In connection with the Transaction, the Company entered into Compensation Agreements (“Compensation Agreements”), each on substantially similar terms, with James A. Winne III, the Company’s former Chairman of the Board and Chief Executive Officer, and Michael Becci, the Company’s former President and Chief Operating Officer. The Compensation Agreements provide for a severance payment equal to $250,000 and the issuance of 17.1037 restricted shares of common stock in the Company, payable to each of Messrs. Winne and Becci promptly upon the Transaction. In exchange for their severance payments, Messrs. Winne and Becci resigned as officers and directors of the Company effective August 16, 2005. This was reported as compensation expense of $3.1 million and included in the transaction expenses in the Predecessor I Company period ended August 15, 2005.
The Company entered into a Contingent Value Agreement (“Contingent Value Agreement”) with the former partners of Capital C, Messrs. Becci and Winne, and the EnerVest funds that purchased Capital C. Under the Contingent Value Agreement, if properties are contributed to a publicly traded partnership or a publicly traded royalty trust (“MLP”), then the Company has agreed to pay the following aggregate amount to the former partners of Capital C, and Messrs. Becci and Winne:
· 20% of the difference between the value received for the assets upon transfer to a MLP and the book value of the assets, if the transfer occurs within one year following the Transaction; and
· 10% of the difference between the value received for the assets upon transfer to a MLP and the book value of the assets, if the transfer occurs in the second year following the Transaction.
Following the Change in Control Transaction, James A. Winne III, resigned as Chairman of the Board of Directors and Chief Executive Officer of the Company, and Michael Becci, resigned as director, President and Chief Operating Officer of the Company. Upon consummation of the Transaction, all of the members of the board of directors of the Company resigned on August 16, 2005 and Capital C replaced the board with John B. Walker, James M. Vanderhider, Mark A. Houser, Ken Mariani and Matthew Coeny. Each such individual shall serve a term ending on the date of the annual meeting of shareholders to be held in 2006.
On August 16, 2005, the board of directors of the Company appointed Mark A. Houser as Chairman and Chief Executive Officer and James M. Vanderhider as President and Chief Operating Officer. On October 3, 2005, James M. Vanderhider resigned as Chief Operating Officer and the Board of Directors of the Company appointed Ken Mariani as its Senior Vice President and Chief Operating Officer. On October 6, 2005, Robert W. Peshek resigned as Senior Vice President and Chief Financial Officer and the Board of Directors of the Company appointed James M. Vanderhider as its Chief Financial Officer.
The Company incurred transaction costs associated with the Transaction of $7.5 million including $500,000 of severance costs. These costs were expensed in the Predecessor I Company period ended August 15, 2005. The Company also capitalized $2.1 million of debt financing costs and recorded obligations of $5.5 million in purchase accounting including $4.2 million of severance cost and $1.2 million of acquisition costs incurred by EnerVest.
(2) Business and Significant Accounting Policies
Business
The Company operates in the oil and gas industry. The Company’s principal business is the exploitation, development, production, operation and acquisition of oil and gas properties. Sales of oil are ultimately made to refineries. Sales of natural gas are ultimately made to gas utilities and industrial consumers in Ohio, Michigan, Pennsylvania and New York. The price of oil and natural gas has a significant impact on our working capital and results of operations.
Principles of Consolidation and Financial Presentation
The accompanying consolidated financial statements include the financial statements of the Company and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain reclassifications have been made to conform to the presentation in 2006.
Use of Estimates in the 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. Significant estimates used in the preparation of the Company’s financial statements which could be subject to significant revision in the near term include estimated oil and gas reserves.
Cash Equivalents
For purposes of the statements of cash flows, cash equivalents are defined as all highly liquid investments purchased with an initial maturity of three months or less.
Concentrations of Credit Risk
Credit limits, ongoing credit evaluation and account monitoring procedures are used to minimize the risk of loss. Collateral is generally not required. Expected losses are provided for currently and actual losses have been within management’s expectations.
Inventories
Inventories of material, pipe and supplies are valued at average cost. Crude oil and natural gas inventories are stated at the lower of average cost or market.
Property and Equipment
The Company uses the “successful efforts” method of accounting for its and gas properties. Under this method, property acquisition and development costs and certain productive exploration costs are capitalized while non-productive exploration costs, which include certain geological and geophysical costs, exploratory dry holes and costs of carrying and retaining undeveloped properties, are expensed as incurred. The costs of carrying and retaining undeveloped properties include delay rental payments made on new and existing leases, ad valorem taxes on existing leases and the cost of previously capitalized leases which are written off because the leases were dropped or expired. Exploratory dry hole costs include the costs associated with drilling an exploratory well that has been determined to be a dry hole. Capitalized costs related to proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties is calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on economic or other factors. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions such as the complete disposition of a geographical/geological pool. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized.
Unproved oil and gas properties are stated at cost and consist of undeveloped leases. These costs are assessed periodically to determine whether their value has been impaired, and if impairment is indicated, the costs are charged to expense. In 2006, we recorded an impairment of $332,000 which reduced the book value of unproved oil and gas properties to their estimated fair value. No impairments were recorded in 2004 and 2005.
Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years.
Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is expensed as incurred, and significant renewals and betterments are capitalized.
Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the difference between the fair value and the carrying amount of the asset. In performing the review for long-lived asset recoverability during 2006, we recorded $214,000 of impairments which reduced the book value of
producing properties to their estimated fair value. Fair value was based on estimated future cash flows to be generated by the assets, discounted at a market rate of interest.
Goodwill and Other Intangible Assets
Under Statement of Financial Accounting Standards No. (SFAS) 142, “Goodwill and Other Intangible Assets” which was issued in June 2001 by the Financial Accounting Standards Board (FASB), goodwill and indefinite lived intangible assets are no longer amortized but are reviewed for impairment annually or if certain impairment indicators arise. Separately identifiable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives (but with no maximum life).
As described in Note 1, the Company recorded goodwill associated with the Transaction which resulted in goodwill of $91.4 million at December 31, 2005 and $90.1 million at December 31, 2006. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets”, goodwill is not amortized to earnings, but is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2006, the Company performed its annual assessment of impairment of the goodwill and determined that there was no impairment.
At December 31, 2006 and 2005, the Company had $1.6 million and $2.0 million, respectively of deferred debt issuance costs. Deferred debt issuance costs are being amortized over their respective terms. Amortization expense related to deferred debt issuance costs was $424,000, $1.2 million and $1.4 million the years ended December 31, 2006, 2005 and 2004, respectively. At December 31, 2006, the amortization of deferred debt issuance costs in the next five years is as follows: $424,000 in each of the next three years (2007 through 2009), $270,000 in 2010 and none in 2011.
Revenue Recognition
Oil and natural gas revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectibility of the revenue is probable. We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under-produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production. There were no material gas imbalances at December 31, 2006 or 2005. Oil and gas marketing revenues are recognized when title passes.
Income Taxes
The Company uses the asset and liability method of accounting for income taxes under SFAS 109, “Accounting for Income Taxes.” Deferred income taxes are provided for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Deferred income taxes also are recognized for operating losses that are available to offset future taxable income and tax credits that are available to offset future federal income taxes. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the benefits will not be realized.
Stock-Based Compensation
On December 31, 2002, the FASB issued SFAS 148, “Accounting for Stock Based Compensation-Transition and Disclosure.” SFAS 148 amends SFAS 123, “Accounting for Stock Based Compensation” by providing alternative methods of transition to SFAS 123’s fair value method of accounting for stock-based compensation. SFAS 148 also amends many of the disclosure requirements of SFAS 123. The Predecessor Companies measured expense associated with stock-based compensation under the provisions of Accounting Principles Board Opinion No. (APB) 25, “Accounting for Stock Issued to Employees” and its related interpretations. Under APB 25, no compensation expense is required to be recognized upon the issuance of stock options to key employees as the exercise price of the option is equal to the market price of the underlying common stock at the date of grant.
The fair value of the Company’s stock options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for the Predecessor II Company period ended July 6, 2004: risk-free interest rates of 3.6% and 3.7%; volatility factor of the expected market price of the Company’s common stock of near zero; dividend yield of zero; and a weighted-average expected life of the option of seven years. There were no stock options granted in the Predecessor I Company 178 day period ended December 31, 2004 or in the years 2005 and 2006.
The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company’s stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management’s opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its stock options.
For purposes of the pro forma disclosures required by SFAS 123, the estimated fair value of the options is amortized to expense over the options’ vesting period. The changes in net income or loss as if we had applied the fair value provisions of SFAS 123 for the Predecessor II Company period ended July 6, 2004 were not material. There were no outstanding stock options or activity in the Successor Company periods ended December 31, 2005 and 2006.
The changes in share value and the vesting of shares are reported as adjustments to compensation expense. The change in share value in the Predecessor II Company period ended July 6, 2004 resulted in an increase in compensation expense of $4.0 million.
In connection with the closing of the Transaction, the Company issued approximately 34 shares of common stock to Messrs. Winne and Becci. The shares were purchased from them at the closing of the Transaction. These shares were reported as compensation expense of $2.6 million and included in the transaction expenses in the Predecessor I Company period ended August 15, 2005.
Derivatives and Hedging
As a result of the adoption of SFAS 133 in 2001, the Company recognizes all derivative financial instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income (loss). Under the provisions of SFAS 133, changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items impact earnings. Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income (loss). Deferred gains and losses on terminated commodity hedges will be recognized as increases or decreases to oil and gas revenues during the same periods in which the underlying forecasted transactions impact earnings. If there is a discontinuance of a cash flow hedge because it is probable that the original forecasted transaction will not occur, deferred gains or losses are recognized in earnings immediately. See Note 5.
The relationship between the hedging instruments and the hedged items must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk, both at the inception of the contract and on an ongoing basis. The Company assesses effectiveness at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Hedge accounting is discontinued prospectively if the Company determines that a derivative is no longer highly effective as a hedge or if the Company decides to discontinue the hedging relationship.
Asset Retirement Obligations
The Company follows SFAS 143, “Accounting for Asset Retirement ” which requires the Company to recognize a liability for the fair value of its asset retirement obligations associated with its tangible, long-lived assets. The majority of the Company’s asset retirement obligations relate to the plugging and abandonment (excluding salvage value) of the Company’s oil and gas properties.
There has been no significant current period activity with respect to additional retirement obligations, settled obligations, accretion expense and revisions of estimated cash flows. The asset retirement obligations increased as a result of purchase accounting for the Transaction and the Merger, primarily due to a lower discount rate, revised estimates of asset lives on certain oil and gas wells and additional wells having been drilled .
A reconciliation of the Company’s liability for plugging and abandonment costs for the years ended December 31, 2006 and 2005 is as follows (in thousands):
(3) New Accounting Pronouncements
In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment.” SFAS 123(R) revises SFAS 123, “Accounting for Stock-Based Compensation”, and focuses on accounting for share-based payments for services by employer to employee. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model and either a binomial or Black-Scholes model may be used. The provisions of SFAS 123(R) are effective for financial statements for fiscal periods ending after June 15, 2005.
SFAS 123(R) must be adopted no later than January 1, 2006 and permits public companies to adopt its requirements using one of two methods:
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A “modified prospective” method in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS 123(R) for all share-based payments granted after the adoption date and based on the requirements of SFAS 123 for all awards granted to employees prior to the effective date of SFAS 123(R) that remain unvested on the adoption date; or
•
A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures.
The Company adopted the provisions of SFAS 123(R) on January 1, 2006 using the modified prospective method.
As permitted by SFAS 123, the Company accounted for share-based payments to employees prior to January 1, 2006 using the intrinsic value method prescribed by APB 25 and related interpretations. As such, the Company generally did not recognize compensation expense associated with employee stock option grants. In 2004, all outstanding stock options were expensed due to the Merger on July 7, 2004. The Successor Company and Predecessor I Company did not have any stock options. The adoption of SFAS 123(R)’s fair value method did not have a significant impact on the Company’s results of operations or financial position.
In February 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 155, Accounting for Certain Hybrid Instruments, to simplify and make more consistent the accounting for certain financial instruments. SFAS No. 155 amends SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to permit fair value remeasurement for any hybrid financial instrument with an embedded derivative that would otherwise require bifurcation, provided that the whole instrument is accounted for on a fair value basis. SFAS No. 155 also amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, to allow a qualifying special purpose entity to hold a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. SFAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We adopted SFAS No. 155 on January 1, 2007, and there was no impact on our consolidated financial statements.
In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement 109” (“FIN 48”), which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is “more-likely-than-not” to be sustained if the position were to be challenged by a taxing authority. The assessment of the tax position is based solely on the technical merits of the position, without regard to the likelihood that the tax position may be challenged. If an uncertain tax position meets the “more-likely-than-not” threshold, the largest amount of tax benefit that is more than 50 percent likely to be recognized upon ultimate settlement with the taxing authority, is recorded. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. Consistent with the requirements of FIN 48, we adopted FIN 48 on January 1, 2007. We are currently evaluating the impact of adopting FIN 48 and do not expect the interpretation will have a material impact on our consolidated financial statements.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 establishes a fair value hierarchy and clarifies the principle that fair value should be based on assumptions market participants would use when pricing the asset or liability. SFAS No. 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We will adopt SFAS No. 157 on January 1, 2008, and we do not expect the adoption to have a material impact on our consolidated financial statements.
In September 2006, the SEC issued Staff Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial
Statements. SAB 108 addresses how the effects of prior year uncorrected misstatements should be considered when quantifying misstatements in current year financial statements. SAB 108 requires companies to quantify misstatements using a balance sheet and income statement approach and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. We adopted SAB 108 on December 31, 2006, and there was no impact on our consolidated financial statements.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been selected are reported in earnings. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We will adopt SFAS No. 159 on January 1, 2008, and we have not yet determined the impact, if any, on our consolidated financial statements.
(4) Dispositions and Discontinued Operations
In August, 2006, we sold our office building in North Canton, Ohio. Net proceeds from the sale were approximately $3.5 million, which was the carrying value of the property.
On March 31, 2006, we sold our interests in 13 Oriskany wells and the associated gas gathering system for approximately $3.3 million, which approximated the net carrying value of such assets.
On June 25, 2004, we completed a sale of substantially all of our Trenton Black River (“TBR”) assets to Fortuna Energy Inc., a wholly owned subsidiary of Talisman Energy Inc. The assets sold included working interests in 16 wells, approximately 11 miles of natural gas gathering lines and oil and gas leases on approximately 475,000 gross acres. The assets are located primarily in New York, Pennsylvania, Ohio and West Virginia. The TBR assets accounted for approximately 5 Bcfe (Billion cubic feet equivalent) of our estimated proved reserves as of December 31, 2003.
The sale resulted in proceeds of approximately $68.2 million. The proceeds were used to pay down the Company’s existing revolving credit facility. As a result of the disposition of the TBR geographical/geological pools, the Company recorded a gain of approximately $46.6 million ($29.8 million net of tax) in June 2004. According to SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the disposition of this group of wells is classified as discontinued operations.
In April 2004, the Company decided to dispose of its Arrow Oilfield Service Company (“Arrow”) assets. The Company sold the Michigan assets of Arrow in May 2004 and sold the Ohio and Pennsylvania assets of Arrow in June 2004. The two Arrow asset sales resulted in proceeds of approximately $4.2 million. As a result of the disposition of all of our Arrow assets, the Company recorded a loss of approximately $1.4 million ($864,000 net of tax) in the second quarter of 2004. According to SFAS 144, the disposition of the Arrow assets is classified as discontinued operations.
The Company allocates interest expense to operating areas based on the proportionate share of net assets of the area to the Company’s consolidated net assets. The amounts of interest expense allocated to income (loss) from discontinued operations for the year ended December 31, 2004 was $907,000.
Revenues and income (loss) from discontinued operations are as follows (in thousands):
(5) Derivatives and Hedging
From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to natural gas price, crude oil price or interest rate volatility and to support its capital expenditure plans. The Company’s derivative financial instruments take the form of swaps or collars. At December 31, 2006, the Company’s derivative contracts were comprised of natural gas swaps, crude oil swaps and interest rate swaps, which were placed with major financial institutions that the Company believes are a minimal credit risk. Qualifying derivative financial instruments are designated as cash flow hedges. Changes in fair value of the derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time the hedged items impact earnings. The changes in fair value of non-qualifying derivative contracts will be reported in expense in the consolidated statements of operations as derivative fair value loss.
The Company uses New York Mercantile Exchange (“NYMEX”) based commodity derivative contracts to hedge natural gas, because the Company’s natural gas production is sold pursuant to NYMEX-based sales contracts. Beginning July 7, 2004, the Company has ineffectiveness on the natural gas swaps due to purchase accounting, which created non-zero value derivatives at the time of the Merger. The Company had collar agreements that could not be redesignated as cash flow hedges because these collars were not effective due to unrealized losses at the date of the Merger. These collars qualified and were designated as cash flow hedges from their inception through the predecessor company period ended July 6, 2004. Although these collars are not deemed to be effective hedges in accordance with the provisions of SFAS 133, the Company retained these instruments as protection against changes in commodity prices and the Company continued to record the mark-to-market adjustments on these natural gas collars, through 2005, in the Company’s income statement. The Company’s NYMEX crude oil swaps were highly effective and were designated as cash flow hedges through August 16, 2005. The Company had ineffectiveness on the crude oil swaps because the oil is sold locally at a posted price which is different from the NYMEX price. At August 16, 2005, the Company’s oil swaps no longer qualify for cash flow hedge accounting because the assessment of effectiveness indicated that they may not be highly effective on an on-going basis. This occurred due to the application of purchase accounting to the derivatives, which created non-zero value derivatives at the time of the Transaction. The changes in the fair values of the natural gas collars since July 7, 2004,
the changes in fair value of the oil swaps subsequent to August 15, 2005, the ineffective portion of the crude oil swaps through August 15, 2005 and the ineffective portion of the natural gas swaps from July 7, 2004 through June 30, 2006 are recorded as “Derivative fair value gain or loss.” As of July 1, 2006, the Company determined that its gas swaps were no longer highly effective and, therefore, could no longer be designated as cash flow hedges. Changes in the fair value of the gas derivatives from that date forward are recorded in derivative fair value gain/loss. Deferred gains or losses on these gas derivatives are recognized as increases or decreases to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings.
During 2006 and 2005, net losses of $3.3 million ($2.2 million after tax) and $34.0 million ($22.9 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. The fair value of open hedges in accumulated other comprehensive income decreased $30.4 million ($19.9 million after tax) in 2006 and increased $291.9 million ($196.6 million after tax) in 2005. At December 31, 2006, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $4.1 million. At December 31, 2006, the Company has partially hedged its exposure to the variability in future cash flows through December 2013.
The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial derivatives (including settled contracts) at December 31, 2006:
Bbl - Barrel
Mmbtu - Million British thermal units
Mbbls - Thousand barrels
Bbtu - Billion British thermal units
At December 31, 2006, the Company had interest rate swaps in place on $80 million of its outstanding debt under the revolving credit facility through September 16, 2008. The swaps provide a 1-month LIBOR fixed rates at 4.285% on $40 million and 5.160% on $40 million plus the applicable margin. At December 31, 2006, the fair value of the interest rate swaps represented an unrealized gain of $481,000.
(6) Details of Balance Sheets
(7) Long-Term Debt
Long-term debt consists of the following (in thousands):
Senior Secured Notes due 2012
The Company has $159.5 million of its Senior Secured Notes (“Notes”) outstanding as of December 31, 2006. As a result of the application of purchase accounting, the notes were recorded as a liability based on the estimated fair value of $200.7 million on the Transaction date. Subsequent accretion of the premium and repurchase of bonds reduced this amount to $165.1 million at December 31, 2006. The fair value adjustment of $5.6 million is shown separately in the table above. The accretion of $865,000 was recorded as a reduction of interest expense in 2006. The Notes mature July 15, 2012. Interest is payable semi-annually on January 15 and July 15 of each year at 8.75% based on the face amount of $159.5 million (for an effective rate of 7.946% based on the fair value on the Transaction date). The Notes are secured on a second-priority lien on the same assets subject to the liens securing the Company’s obligations under the Senior Facilities (defined hereinafter). The Notes are subject to redemption at the Company’s option at specific redemption prices.
The Notes are governed by an indenture (the “Indenture”), which contains certain covenants that limit our ability to incur additional indebtedness and issue stock, pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing indebtedness of any kind other than permitted liens and engage in mergers and consolidations.
Amended Credit Agreement
On August 16, 2005, the Company amended and restated its then existing $170 million credit agreement, by entering into a First Amended and Restated Credit and Guaranty Agreement (“Amended Credit Agreement”) by and among the Company and BNP Paribas, as sole lead arranger, sole book runner, syndication agent and administrative agent. The Amended Credit Agreement provides for loans and other extensions of credit to be made to the Company up to a maximum aggregate principal amount of $390 million. The obligations under the Amended Credit Agreement are secured by substantially all of
the assets of the Company. J.P. Morgan Chase and Amegy Bank were added to the bank group in September 2005.
The Amended Credit Agreement provides for a revolving credit line in the aggregate principal amount of $350 million and a hedge letter of credit facility in the aggregate principal amount of $40 million (collectively, the “Senior Facilities”). Borrowings under the Amended Credit Agreement may not exceed the borrowing base, which was initially set at $80.25 million, of which $57 million was drawn at closing on August 16, 2005. At December 31, 2006, the borrowing base was $113.4 million and the outstanding balance was $95.4 million.
Borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate or an adjusted federal funds rate, plus an applicable margin ranging from 0% to 0.625% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at the Company’s option, the Eurodollar base rate plus an applicable margin ranging from 1.125% to 2.125% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2010.
The obligations under the Amended Credit Agreement are secured by a first lien security interest in substantially all of the assets of the Company. The obligations under the Amended Credit Agreement are further secured by a pledge of 100% of the capital stock of the Company held by Capital C, the Company’s parent. This agreement was amended on September 27, 2005 to reduce the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 70%.
The Amended Credit Agreement contains covenants that will limit the ability of the Company to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock of the Company or its subsidiaries; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber the capital stock of the Company or its subsidiaries; or enter into transactions with affiliates. The Amended Credit Agreement also requires compliance with customary financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a minimum current ratio. As of December 31, 2006, we were in compliance with all financial covenants and requirements under the existing credit facilities.
Borrowings under the revolving credit line will be used by the Company for general corporate purposes. In accordance with the terms of the Amended Credit Agreement, letters of credit issued under the hedge letter of credit commitment and any related borrowings are to be used solely to secure payment of the Company’s obligations under the J. Aron Swap (defined hereinafter).
In connection with the Company’s entry into the Amended Credit Agreement, the Company executed a Subordinated Promissory Note (“Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Note, Capital C loaned $25 million to the Company on August 16, 2005. The Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the Note made on August 16, 2005. Interest payments on the Note are due quarterly commencing September 30, 2005. In lieu of cash payments, the Company has the option to make interest payments on the Note by borrowing additional amounts against the Note. The interest payments in 2005 and 2006 were paid in cash. The Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. The Note is expressly subordinate to the Company’s senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap and notes issued under the Company’s Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee (“Senior Secured Notes”).
ISDA Master Agreement
The Company amended and restated the Schedule and Credit Support Annex to its International Swap Dealers Association (“ISDA”) Master Agreement, dated as of June 30, 2004, by and between the Company and J. Aron & Company (“J. Aron Swap”), pursuant to which the Company has agreed, from time to time, to enter into cash-settled hedge transactions with J. Aron & Company, as hedge counterparty, in connection with various gas and oil commodity derivatives transactions. The amendments to the J. Aron Swap conform the terms of the Schedule and Credit Support Annex to the terms of the Amended Credit Agreement, change certain covenants and reduce the maximum amount of the letter of credit securing the hedge obligations from $55 million to $40 million.
At December 31, 2006, the aggregate long-term debt maturing in the next five years is as follows: $7,000 (2007); $8,000 (2008); $8,000 (2009); $95.4 million (2010) and $184.5 million (2011 and thereafter). Our term loan facility requires mandatory prepayments annually based on the calculation of excess cash flow, as defined in the agreement.
(8) Leases
The Company leases certain computer equipment, vehicles, natural gas compressors and office space under noncancelable agreements with lease periods of one to five years. Rent expense amounted to $3.1 million in 2006, $1.3 million in the Successor Company 138 day period ended December 31, 2005, $2.1 million in the Predecessor I Company 227 day period ended August 15, 2005, $1.7 million for the Predecessor I Company 178 day period ended December 31, 2004, and $2.9 million for the Predecessor II Company 188 day period ended July 6, 2004.
The Company also leases certain computer equipment accounted for as capital leases. Property and equipment includes $273,000 of computer equipment under capital leases at December 31, 2006 and 2005. Accumulated depreciation for such equipment includes approximately $236,000 and $176,000 at December 31, 2006 and 2005, respectively.
Future minimum commitments under leasing arrangements as of December 31, 2006 were as follows:
(9) Stock Option Plans
We have a 1997 non-qualified stock option plan under which we are authorized to issue up to 1,466 shares of common stock to officers and employees. The exercise price of options may not be less than the fair market value of a share of common stock on the date of grant. Options expire on the
tenth anniversary of the grant date unless cessation of employment causes earlier termination. No options were granted during 2005 or 2006 and as of December 31, 2006, no options were outstanding under the plan. The Company has no intentions to grant any options.
Stock option activity consisted of the following:
The weighted average fair value of options granted during 2004 were $0.87.
(10) Taxes
The provision (benefit) for income taxes on income from continuing operations before cumulative effect of change in accounting principle includes the following (in thousands):
Changes in the effective state tax rate due to changes in the state apportionment rates are included in state income taxes, net of federal income tax benefit.
On June 30, 2005 the State of Ohio enacted new tax legislation that will result in the elimination of the income and franchise tax over a four year period and it will be replaced with a gross receipts based tax. As a result of the new tax structure, the Company recorded a tax benefit of $1.1 million to adjust the recorded deferred tax account balances for Ohio during 2005.
Significant components of deferred income tax liabilities and assets are as follows (in thousands):
At December 31, 2006, the Company had approximately $37.1 million of net operating loss carryforwards available for federal income tax reporting purposes. These net operating loss carryforwards, if unused, will expire in 2019 through 2025. The Company also had state net operating losses aggregating $249.1 million, which expire between 2007 and 2025. The net operating losses are subject to annual limitations due to IRC Section 382 as a result of the Merger in 2004 and the Transaction in 2005. SFAS No. 109 requires a valuation allowance to be recorded when it is more likely than not that some or all of the deferred tax assets will not be realized. We do not believe the application of Section 382 hinders our ability to utilize the federal net operating losses and, accordingly, no valuation allowance has been recorded. The valuation allowance of $11.5 million relates to certain state net operating loss carryforwards which we estimate would expire before they could be used. We have alternative minimum tax credit carryforwards of approximately $1.8 million, which have no expiration date.
(11) Profit Sharing and Retirement Plans
Prior to 2006, the Company had a non-qualified profit sharing arrangement under which the Company contributed discretionary amounts determined by the compensation committee of the Company’s Board of Directors based on attainment of performance targets. Amounts were allocated to substantially all employees based on relative compensation. The Company expensed $417,000 for the Successor Company 138 day period ended December 31, 2005, $96,000 for the Predecessor I Company 227 day period ended August 15, 2005, $428,000 for the Predecessor I Company’s 178 day period ended
December 31, 2004, and $544,000 for the Predecessor II Company 188 day period ended July 6, 2004, for contributions to the profit sharing plan and discretionary bonuses. All amounts were paid in cash.
Effective April 1, 2006 the Company’s 401(k) retirement plan merged into the EnerVest Management Partners, Ltd., 401(k) Plan.
As of December 31, 2005, the Company had a 401(k) retirement plan which covered substantially all of the employees of the Company. Eligible employees made voluntary contributions which the Company matches $1.00 for every $1.00 contributed up to 4% of an employee’s annual compensation and a $0.50 match for every $1.00 contributed up to the next 2% of compensation. Retirement plan expense amounted to $83,000 for the Successor Company 138 day period ended December 31, 2005, $255,000 for the Predecessor I Company 227 day period ended August 15, 2005, $121,000 for the Predecessor I Company 178 day period ended December 31, 2004, and $237,000 for the Predecessor II Company 188 day period ended July 6, 2004.
(12) Commitments and Contingencies
In February 2000, four individuals filed a suit in Chautauqua County, New York on their own behalf and on the behalf of others similarly situated, seeking damages for the alleged difference between the amount of lease royalties actually paid and the amount of royalties that allegedly should have been paid. Other natural gas producers in New York were served with similar complaints. On October 10, 2005, we were granted a summary judgment that dismissed all claims. The plaintiff filed a notice of appeal and had nine months to file their brief. The Company’s counsel has advised us that the plaintiffs in this case have failed to file their appeal timely, therefore our summary judgment stands and the case is dismissed.
The Company is involved in several lawsuits arising in the ordinary course of business. The Company believes that the result of such proceedings, individually or in the aggregate, will not have a material adverse effect on its financial position, results of operations or cash flows.
(13) Supplemental Disclosure of Cash Flow Information
(14) Fair Value of Financial Instruments
The fair value of the financial instruments disclosed herein is not representative of the amount that could be realized or settled, nor does the fair value amount consider the tax consequences, if any, of realization or settlement. The amounts in the financial statements for cash equivalents, accounts receivable and notes receivable approximate fair value due to the short maturities of these instruments. The recorded amounts of outstanding bank and other long-term debt approximate fair value because interest rates are based on LIBOR or the prime rate or due to the short maturities. The $159.5 million (face amount) of the Company’s Senior Secured Notes due 2012 had an approximate fair value of $162.7 million at December 31, 2006 based on quoted market prices.
From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to natural gas or oil price volatility. The Company employs a policy of hedging gas production sold under NYMEX-based contracts by selling NYMEX-based commodity derivative contracts. The Company’s NYMEX crude oil swaps are sold locally at posted price which is different from the NYMEX price. Historically there has been a high correlation between the posted price and NYMEX. The contracts may take the form of futures contracts, swaps, collars or options which are placed with major financial institutions that we believe are minimal credit risks. At December 31, 2006, the Company’s derivative contracts consisted of natural gas swaps, crude oil swaps and interest rate swaps. At December 31, 2006, the fair value of the derivative contracts covering 2007 through 2013 oil and gas production represented an unrealized loss of $187.5 million. At December 31, 2006, the fair value of the Company’s interest rate contract covering 2007 through September 2008 represented an unrealized gain of $481,000.
(15) Supplementary Information on Oil and Gas Activities (Unaudited)
The following disclosures of costs incurred related to oil and gas activities from continuing operations are presented in accordance with SFAS 69.
Estimated Proved Oil and Gas Reserves (Unaudited)
Our estimated proved developed and estimated proved undeveloped reserves are all located within the United States. We caution that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil and gas reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used. Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Estimated proved developed reserves are estimated proved reserves expected to be recovered through wells and equipment in place and under operating methods being used at the time the estimates were made. The estimates of proved reserves as of December 31, 2006, 2005 and 2004 have been prepared by Wright & Company, Inc., independent petroleum consultants. The estimated proved reserve information for the 2004 Predecessor II Company 188 day period ended July 6, 2004 and the 2005 Predecessor I Company 227 day period ended August 15, 2005, is based on our internal engineering estimates.
The following table sets forth changes in estimated proved and estimated proved developed reserves for the periods indicated:
(1) Thousand barrels
(2) Million cubic feet
(3) Million cubic feet equivalent, barrels are converted to Mcfe based on one barrel of oil to six Mcf of natural gas equivalent.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)
The following tables, which present a standardized measure of discounted future net cash flows and changes therein relating to estimated proved oil and gas reserves, are presented pursuant to SFAS No. 69. In computing this data, assumptions other than those required by the FASB could produce different
results. Accordingly, the data should not be construed as representative of the fair market value of our estimated proved oil and gas reserves. The following assumptions have been made:
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Future revenues were based on year-end oil and gas prices. Future price changes were included only to the extent provided by existing contractual agreements.
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Production and development costs were computed using year-end costs assuming no change in present economic conditions.
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Future net cash flows were discounted at an annual rate of 10%.
-
Future income taxes were computed using the approximate statutory tax rate and giving effect to available net operating losses, tax credits and statutory depletion.
The standardized measure of discounted future net cash flows relating to estimated proved oil and gas reserves is presented below:
At December 31, 2006, as specified by the SEC, the prices for oil and natural gas used in this calculation were regional cash price quotes on the last day of the year except for volumes subject to fixed price contracts. The weighted average prices for the total estimated proved reserves at December 31, 2006 were $5.91 per Mcf of natural gas and $57.21 per barrel of oil. We do not include our natural gas and crude oil derivative instruments, consisting of swaps and collars, in the determination of our oil and gas reserves.
\
The principal sources of changes in the standardized measure of future net cash flows are as follows:
(16) Industry Segment Financial Information
We operate in one reportable segment, as an independent energy company engaged in producing oil and natural gas; exploring for and developing oil and gas reserves; acquiring and enhancing the economic performance of producing oil and gas properties; and marketing and gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. Our operations are conducted entirely in the United States.
Major customers
During 2006, we had three customers that each accounted for 10% or more of consolidated revenues with sales of $21.4 million, $20.1 million and $18.5 million, respectively. During 2005, we had three customers that each accounted for 10% or more of consolidated revenues with sales of $21.1 million, $20.5 million and $20.3 million, respectively. During 2004, we had three customers that each accounted for 10% or more of consolidated revenues with sales of $19.9 million, $14.6 million and $12.6 million, respectively.
(17) Quarterly Results of Operations (Unaudited)
The results of operations for the four quarters of 2006 and 2005 are shown below (in thousands).
(18) Related Party Transactions
On August 16, 2005, the former partners of Capital C completed the sale of all of the partnership interests in Capital C to certain institutional funds managed by EnerVest Management Partners, Ltd. (“EnerVest”). EnerVest incurred and was reimbursed by the Company $1.1 million for transaction costs. This amount was recorded as an accrued expense at December 31, 2005 and was paid in January 2006.
On March 15, 2006, the Company entered into a joint operating agreement with EnerVest Operating L.L.C. (“EnerVest Operating”), a subsidiary of EnerVest. The joint operating agreement was effective October 1, 2005 and resulted in expense to the Company of $642,000 in 2005 and $5.3 million in 2006 for overhead fees. We also paid $6.7 million for field labor, vehicles and district office expense, $875,000 for drilling overhead fees and $1.3 million for drilling labor costs in 2006 related to this agreement. We reimbursed EnerVest Operating for expenses of $332,000 in 2006 related to the transition of accounting responsibilities to EnerVest Operating’s Charleston, West Virginia office.
The Company paid approximately $211,000 to Opportune LLP in the 2006 for consulting services related to the Company’s amended filings and the 2005 Form 10-K. John Vanderhider, brother of James Vanderhider, the Company’s President and Chief Financial Officer, is a partner with Opportune.
The Company paid approximately $207,000 to PetroAcct LP in 2006 for services related to the transition of accounting and information system responsibilities from the Company to EnerVest Operating. A subsidiary of EnerVest Management Partners, Ltd owned 50% of PetroAcct during 2006. The 50% ownership interest in PetroAcct was sold to Opportune in March 2007.
As of December 31, 2006, we owed EnerVest Operating $1,243,000 and EnerVest owed us $520,000.
In connection with the Transaction, the Company executed a subordinated promissory note in favor of the Company’s parent, Capital C in the maximum amount of $94 million. Under the note, Capital C loaned $25 million to the Company on August 16, 2005 in connection with the Transaction. The note accrues interest at 10% per year and matures on August 16, 2012. The Company received a fairness opinion from an unrelated financial services firm with respect to the terms of the note made on August 16, 2005. Interest payments on the note are due quarterly commencing September 30, 2005. In lieu of cash payments, the Company has the option to make interest payments on the note by borrowing additional amounts against the note. The amount due under the note at December 31, 2005 was $25 million. We made cash payments of $945,000 in 2005 and $2.5 million in 2006.
Messrs. Houser, Vanderhider and Mariani are officers and directors of the Company and they are officers and equity owners of EnerVest and EnerVest Operating. The institutional funds that are managed by EnerVest and own our direct parent, Capital C, also hold other investments in oil and gas assets and operations. The Company can give no assurance that conflicts of interest will not arise for corporate opportunities. Also, the Company can give no assurance that conflicts will not arise with respect to the time and attention devoted to the Company by Messrs. Houser, Vanderhider and Mariani.