Item 1A.
Risk Factors.
Risks Relating to the Oil and Natural Gas Industry and Our Business
Oil and natural gas prices are volatile, and a decline in oil and natural gas prices would reduce our revenues, profitability and cash flow and impede our growth.
Our revenues, profitability and cash flow depend substantially upon the prices and demand for oil and natural gas. The markets for these commodities are volatile and even relatively modest drops in prices can affect significantly our financial results and impede our growth. Oil and natural gas prices are currently at or near historical highs and may fluctuate and decline significantly in the near future. Prices for oil and natural gas fluctuate in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:
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domestic and foreign supply of oil and natural gas;
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price and quantity of foreign imports;
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actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;
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level of consumer product demand;
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domestic and foreign governmental regulations;
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political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;
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weather conditions;
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technological advances affecting oil and natural gas consumption;
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overall U.S. and global economic conditions; and
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price and availability of alternative fuels.
Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 62% of our estimated proved reserves (68% on a pro forma basis) as of December 31, 2005 were natural gas reserves, our financial results are more sensitive to movements in natural gas prices. Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will affect materially the quantities and present value of our reserves, which may lower our bank borrowing base and reduce our access to capital.
Estimating oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing estimates we project production rates and timing of development expenditures. We also analyze the available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates, perhaps significantly. 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, 2005, 50% of our estimated proved reserves were proved undeveloped (44% on a pro forma basis).
If the interpretations or assumptions we use in arriving at our estimates prove to be inaccurate, the amount of oil and natural gas that we ultimately recover may differ materially from the estimated quantities and net present value of reserves shown in this Annual Report. See “- Estimated Proved Reserves” under Items 1 and 2 for information about our oil and gas reserves.
In estimating future net revenues from proved reserves, we assume that future prices and costs are fixed and apply a fixed discount factor. If these assumptions or discount factor are materially inaccurate, our revenues, profitability and cash flow could be materially less than our estimates.
The present value of future net revenues from our proved reserves referred to in this Annual Report is not necessarily the actual current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on fixed prices and costs as of the date of the estimate. Actual future prices and costs fluctuate over time and may differ materially from those used in the present value estimate. In addition, discounted future net cash flows are estimated assuming that royalties to the MMS with respect to our affected offshore Gulf of Mexico properties will be paid or suspended for the life of the properties based upon oil and natural gas prices as of the date of the estimate. See “- Royalty Relief” under Items 1 and 2, and “Legal Proceedings” under Item 3. Since actual future prices fluctuate over time, royalties may be required to be paid for various portions of the life of the properties and suspended for other portions of the life of the properties.
The timing of both the production and expenses from the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In addition, the 10% discount factor that we use to calculate the net present value of future net cash flows for reporting purposes in accordance with the SEC’s rules may not necessarily be the most appropriate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor in arriving at an accurate net present value of future net cash flows.
If oil and natural gas prices decrease, we may be required to write-down the carrying value and/or the estimates of total reserves of our oil and natural gas properties.
Accounting rules applicable to us require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur non-cash charges in the future, which could have a material adverse effect on our results of operations in the period taken. We may also reduce our estimates of the reserves that may be economically recovered, which could have the effect of reducing the value of our reserves.
We need to replace our reserves at a faster rate than companies whose reserves have longer production periods. Our failure to replace our reserves would result in decreasing reserves and production over time.
Unless we conduct successful exploration and development activities or acquire properties containing proven reserves, our proved reserves will decline as reserves are depleted. Producing oil and natural gas reserves are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. High production rates generally result in recovery of a relatively higher percentage of reserves from properties during the initial few years of production. A significant portion of our current operations are conducted in the Gulf of Mexico, especially since our merger with Forest Energy Resources. Production from reserves in the Gulf of Mexico generally declines more rapidly than reserves from reservoirs in other producing regions. As a result, our need to replace reserves from new investments is relatively greater than those of producers who produce lower percentages of their reserves over a similar time period, such as
those producers who have a portion of their reserves outside of the Gulf of Mexico in areas where the rate of reserve production is lower. If we are not able to find, develop or acquire additional reserves to replace our current and future production, our production rates will decline even if we drill the undeveloped locations that were included in our proved reserves. Our future oil and natural gas reserves and production, and therefore our cash flow and income, are dependent on our success in economically finding or acquiring new reserves and efficiently developing our existing reserves.
Approximately 65% of our total estimated proved reserves are developed non-producing or undeveloped (71% on a pro forma basis), and those reserves may not ultimately be produced or developed.
As of December 31, 2005, approximately 15% of our total estimated proved reserves were developed non-producing (27% on a pro forma basis) and approximately 50% were undeveloped (44% on a pro forma basis). These reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced at the time periods we have planned, at the costs we have budgeted, or at all. As a result, we may not find commercially viable quantities of oil and natural gas, which in turn may have a material adverse effect on our results of operations.
Any production problems related to our Gulf of Mexico properties could reduce our revenue, profitability and cash flow materially.
A substantial portion of our exploration and production activities is located in the Gulf of Mexico. This concentration of activity makes us more vulnerable than some other industry participants to the risks associated with the Gulf of Mexico, including delays and increased costs relating to adverse weather conditions such as hurricanes, which are common in the Gulf of Mexico during certain times of the year, drilling rig and other oilfield services and compliance with environmental and other laws and regulations.
Our exploration and development activities may not be commercially successful.
Exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, 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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adverse weather conditions, including hurricanes, which are common in the Gulf of Mexico during certain times of the year;
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compliance with governmental regulations;
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unavailability or high cost of drilling rigs, equipment or labor;
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reductions in oil and natural gas prices; and
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limitations in the market for oil and natural gas.
If any of these factors were to occur with respect to a particular project, we could lose all or a part of our investment in the project, or we could fail to realize the expected benefits from the project, either of which could materially and adversely affect our revenues and profitability.
Our exploratory drilling projects are based in part on seismic data, which is costly and cannot ensure the commercial success of the project.
Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of
which are often uncertain. Even when used and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators. 3-D seismic data does not enable an interpreter to conclusively determine whether hydrocarbons are present or producible economically. In addition, the use of 3-D seismic and other advanced technologies require greater predrilling expenditures than traditional drilling strategies. Because of these factors, we could incur losses as a result of exploratory drilling expenditures. Poor results from exploration activities could have a material adverse effect on our future cash flows, ability to replace reserves and results of operations.
Oil and gas drilling and production involve many business and operating risks, any one of which could reduce our levels of production, cause substantial losses or prevent us from realizing profits.
Our business is subject to all of the operating risks associated with drilling for and producing oil and natural gas, including:
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fires;
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explosions;
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blow-outs and surface cratering;
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uncontrollable flows of underground natural gas, oil and formation water;
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natural disasters, such as hurricanes and other adverse weather conditions;
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pipe or cement failures;
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casing collapses;
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lost or damaged oilfield drilling and service tools;
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abnormally pressured formations; and
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environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.
If any of these events occurs, we could incur substantial losses as a result of injury or loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of our operations and repairs to resume operations.
Our offshore operations involve special risks that could increase our cost of operations and adversely affect our ability to produce oil and gas.
Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. For more information on the impact of recent hurricanes on our operations, see “ - Recent Developments” under Item 7.
Exploration for oil or natural gas in the deepwater of the Gulf of Mexico generally involves greater operational and financial risks than exploration on the shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. Our deepwater wells use subsea completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics. These operations may encounter mechanical difficulties and equipment failures that could result in significant cost overruns. Furthermore, the deepwater operations generally lack the physical and oilfield service infrastructure present in the shallow waters of the Gulf of Mexico. As a result, a significant amount of time may elapse between a deepwater discovery and our marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with
these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the deepwater may never be produced economically.
Our hedging transactions may not protect us adequately from fluctuations in oil and natural gas prices and may limit future potential gains from increases in commodity prices or result in losses.
We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. These financial arrangements typically take the form of price swap contracts and costless collars. Hedging arrangements expose us to the risk of financial loss in some circumstances, including situations when the other party to the hedging contract defaults on its contract or production is less than expected. During periods of high commodity prices, hedging arrangements may limit significantly the extent to which we can realize financial gains from such higher prices. For example, in calendar year 2005, our hedging arrangements reduced the benefit we received from increases in the prices for oil and natural gas by approximately $49 million. Although we currently maintain an active hedging program, we may choose not to engage in hedging transactions in the future. As a result, we may be affected adversely during periods of declining oil and natural gas prices.
We will require additional capital to fund our future activities. If we fail to obtain additional capital, we may not be able to implement fully our business plan, which could lead to a decline in reserves.
We depend on our ability to obtain financing beyond our cash flow from operations. Historically, we have financed our business plan and operations primarily with internally generated cash flow, bank borrowings, proceeds from the sale of oil and natural gas properties, exploration arrangements with other parties, the issuance of debt securities, privately raised equity and, prior to the bankruptcy of Enron Corp. (our indirect parent company until March 2, 2004), borrowings from Enron affiliates. In the future, we will require substantial capital to fund our business plan and operations. We expect to be required to meet our needs from our excess cash flow, debt financings and additional equity offerings (subject to certain federal tax limitations during the two-year period following the spin-off). Sufficient capital may not be available on acceptable terms or at all. If we cannot obtain additional capital resources, we may curtail our drilling, development and other activities or be forced to sell some of our assets on unfavorable terms.
The issuance of additional debt would require that a portion of our cash flow from operations be used for the payment of interest on our debt, thereby reducing our ability to use our cash flow to fund working capital, capital expenditures, acquisitions and general corporate requirements, which could place us at a competitive disadvantage relative to other competitors. Additionally, if revenues decrease as a result of lower oil or natural gas prices, operating difficulties or declines in reserves, our ability to obtain the capital necessary to undertake or complete future exploration and development programs and to pursue other opportunities may be limited, which could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could result in a decline in our oil and natural gas reserves.
Properties we acquire (including the Forest Gulf of Mexico properties) may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.
Properties we acquire, including the Forest Gulf of Mexico properties, may not produce as expected, may be in an unexpected condition and may subject us to increased costs and liabilities, including environmental liabilities. The reviews we conduct of acquired properties prior to acquisition are not capable of identifying all potential adverse conditions. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties or properties with known adverse conditions and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems or permit a buyer to become sufficiently familiar with the properties to assess fully their condition, any deficiencies, and development potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.
Market conditions or transportation impediments may hinder our access to oil and natural gas markets or delay our production.
Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines or trucking and terminal facilities. In deepwater operations, the availability of a ready market depends on the proximity of and our ability to tie into existing production platforms owned or operated by others and the ability to negotiate commercially satisfactory arrangements with the owners or operators. We may be required to shut in wells or delay initial production for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we are unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.
The unavailability or high cost of drilling rigs, equipment, supplies or personnel could affect adversely our ability to execute on a timely basis our exploration and development plans within budget, which could have a material adverse effect on our financial condition and results of operations.
Shortages in availability or the high cost of drilling rigs, equipment, supplies or personnel could delay or affect adversely our exploration and development operations, which could have a material adverse effect on our financial condition and results of operations. An increase in drilling activity in the U.S. or the Gulf of Mexico could increase the cost and decrease the availability of necessary drilling rigs, equipment, supplies and personnel.
Competition in the oil and natural gas industry is intense, and many of our competitors have resources that are greater than ours giving them an advantage in evaluating and obtaining properties and prospects.
We operate in a highly competitive environment for acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel. Many of our competitors are major and large independent oil and natural gas companies, and possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional prospects and discover reserves in the future will depend on our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.
Financial difficulties encountered by our farm-out partners or third-party operators could adversely affect our ability to timely complete the exploration and development of certain prospects.
From time to time, we enter into farm-out agreements to fund a portion of the exploration and development costs of our prospects. Moreover, other companies operate some of the other properties in which we have an ownership interest. Liquidity and cash flow problems encountered by our partners and co-owners of our properties may lead to a delay in the pace of drilling or project development that may be detrimental to a project. In addition, our farm-out partners and working interest owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farm-out partner, we may have to obtain alternative funding in order to complete the exploration and development of the prospects subject to the farm-out agreement. In the case of a working interest owner, we may be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary in order to fund either of these contingencies.
We cannot control the timing or scope of drilling and development activities on properties we do not operate, and therefore we may not be in a position to control the associated costs or the rate of production of the reserves.
Other companies operate some of the properties in which we have an interest. As a result, we have a limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of drilling and development activities on properties operated by others therefore depend upon a number of factors that are outside of our control, including timing and amount of capital expenditures, the operator’s expertise and financial resources, approval of other participants in drilling wells and selection of technology.
Compliance with environmental and other government regulations could be costly and could affect production negatively.
Exploration for and development, production and sale of oil and natural gas in the U.S. and the Gulf of Mexico are subject to extensive federal, state and local laws and regulations, including environmental and health and safety laws and regulations. We may be required to make large expenditures to comply with these environmental and other requirements. Matters subject to regulation include, among others, environmental assessment prior to development, discharge and emission permits for drilling and production operations, drilling bonds, and reports concerning operations and taxation.
Under these laws and regulations, and also common law causes of action, we could be liable for personal injuries, property damage, oil spills, discharge of pollutants and hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations or to obtain or comply with required permits may result in the suspension or termination of our operations and subject us to remedial obligations as well as administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs. We cannot predict how agencies or courts will interpret existing laws and regulations, whether additional or more stringent laws and regulations will be adopted or the effect these interpretations and adoptions may have on our business or financial condition. For example, the OPA imposes a variety of regulations on “responsible parties” related to the prevention of oil spills. The implementation of new, or the modification of existing, environmental laws or regulations promulgated pursuant to the OPA could have a material adverse impact on us. Further, Congress or the MMS could decide to limit exploratory drilling or natural gas production in additional areas of the Gulf of Mexico. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition and results of operations. See “- Regulation” under Items 1 and 2 for more information on our regulatory and environmental matters.
Compliance with MMS regulations could significantly delay or curtail our operations or require us to make material expenditures, all of which could have a material adverse effect on our financial condition or results of operations.
A significant portion of our operations are located on federal oil and natural gas leases that are administered by the MMS. As an offshore operator, we must obtain MMS approval for our exploration, development and production plans prior to commencing such operations. The MMS has promulgated regulations that, among other things, require us to meet stringent engineering and construction specifications, restrict the flaring or venting of natural gas, govern the plug and abandonment of wells located offshore and the installation and removal of all production facilities, and govern the calculation of royalties and the valuation of crude oil produced from federal leases.
Our insurance may not protect us against our business and operating risks.
We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is
excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.
Although we maintain insurance at levels which we believe are appropriate and consistent with industry practice, we are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations. The impact of Hurricanes Katrina and Rita have resulted in escalating insurance costs and less favorable coverage terms. In addition, we have not yet been able to determine the full extent of our insurance recovery and the resulting net cost to us for the hurricanes. See “- Insurance Matters” under Items 1 and 2 for more information.
Risks Relating to Our Merger with Forest Energy Resources
The integration of the Forest Gulf of Mexico operations will be difficult, and will divert our management’s attention away from our normal operations.
There is a significant degree of difficulty and management involvement inherent in the process of integrating the Forest Gulf of Mexico operations. These difficulties include:
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the challenge of integrating the Forest Gulf of Mexico operations while carrying on the ongoing operations of our business;
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the challenge of managing a significantly larger company, with more than twice the PV10 of Mariner prior to the merger;
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the possibility of faulty assumptions underlying our expectations;
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the difficulty associated with coordinating geographically separate organizations;
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the challenge of integrating the business cultures of the two companies;
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attracting and retaining personnel associated with the Forest Gulf of Mexico operations following the merger; and
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the challenge and cost of integrating the information technology systems of the two companies.
The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
If we fail to realize the anticipated benefits of the merger, our results of operations may be lower than we expect.
The success of the merger will depend, in part, on our ability to realize the anticipated growth opportunities from combining the Forest Gulf of Mexico operations with Mariner. Even if we are able to successfully combine the two businesses, it may not be possible to realize the full benefits of the proved reserves, enhanced growth of production volume, cost savings from operating synergies and other benefits that we currently expect to result from the merger, or realize these benefits within the time frame that is currently expected. The benefits of the merger may be offset by operating losses relating to changes in commodity prices, or in oil and gas industry conditions, or by risks and uncertainties relating to the combined company’s exploratory prospects, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from the merger, our results of operations may be adversely affected.
We expect to incur significant charges relating to the integration plan that could materially and adversely affect our period-to-period results of operations.
We anticipate that from time to time we will incur charges to our earnings in connection with the integration of the Forest Gulf of Mexico operations into our business. These charges will include expenses incurred in connection with relocating and retaining employees and increased professional and consulting costs. We also expect to incur significant expenses related to being a public company. We are not yet able to quantify the costs or timing of the integration. Some factors affecting the cost of the integration include the training of new employees, the amount of severance and other employee-related payments resulting from the merger, and the limited length of time during which transitional services are provided by Forest.
In order to preserve the tax-free treatment of the spin-off of Forest Energy Resources, we are required to abide by potentially significant restrictions which could limit our ability to undertake certain corporate actions (such as the issuance of our common shares or the undertaking of a change in control) that otherwise could be advantageous.
In connection with the merger we entered into a tax sharing agreement, which imposes ongoing restrictions on Forest and on us to ensure that applicable statutory requirements under the Internal Revenue Code of 1986, as amended, or the Code, and applicable Treasury regulations continue to be met so that the spin-off of Forest Energy Resources remains tax-free to Forest and its shareholders. As a result of these restrictions, our ability to engage in certain transactions, such as the redemption of our common stock, the issuance of equity securities and the utilization of our stock as currency in an acquisition, will be limited for a period of two years following the spin-off.
If Forest or Mariner takes or permits an action to be taken (or omits to take an action) that causes the spin-off to become taxable, the relevant entity generally will be required to bear the cost of the resulting tax liability to the extent that the liability results from the actions or omissions of that entity. If the spin-off became taxable, Forest would be expected to recognize a substantial amount of income, which would result in a material amount of taxes. Any such taxes allocated to us would be expected to be material to us, and could cause our business, financial condition and operating results to suffer. These restrictions may reduce our ability to engage in certain business transactions that otherwise might be advantageous to us and could have a negative impact on our business.
Item 1B.
Item 1B.
Unresolved Staff Comments.
None.
Item 3.
Item 3.
Legal Proceedings.
Mariner operates numerous properties in the Gulf of Mexico. Two of these properties were leased from the MMS subject to the RRA. The RRA relieved the obligation to pay royalties on certain predetermined leases until a designated volume is produced. These two leases contained language that limited royalty relief if commodity prices exceeded predetermined levels. In 2000, 2001, 2003, 2004 and 2005 commodity prices exceeded the predetermined levels. Management believes the MMS did not have the authority to set pricing limits and we filed an administrative appeal contesting the MMS’ order and have withheld royalties regarding this matter. The MMS filed a motion to dismiss our appeal with the Board of Land Appeals of the Department of the Interior. On April 6, 2005, the Board of Land Appeals granted MMS’ motion and dismissed our appeal. On October 3, 2005, we filed suit in the U.S. District Court for the Southern District of Texas seeking judicial review of the dismissal of our appeal by the Board of Land Appeals. Mariner has recorded a liability for 100% of the potential exposure on this matter, which on December 31, 2005 was $16.0 million.
In addition to the foregoing, by letter dated December 2, 2005, the MMS notified Mariner that 2004 commodity prices exceeded the predetermined levels and, accordingly, that royalties were due on natural gas and oil produced in calendar year 2004 from federal offshore leases with confirmed royalty suspension volumes as defined by the RRA. On December 29, 2005, Mariner filed a notice of intent to appeal this royalty demand from the MMS. Mariner has paid royalties on calendar year 2004 production from federal offshore leases in which it owns an interest except for 2004 production from Ewing Bank 966 and Garden Banks 367, which are the two leases at issue in the lawsuit discussed above.
In the ordinary course of business, we are a claimant and/or a defendant in various legal proceedings, including proceedings as to which we have insurance coverage, in which the exposure, individually and in the aggregate, is not considered material by and to us.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders.
Not applicable.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
The shares of Mariner common stock are listed and traded on the New York Stock Exchange (“NYSE”), under the symbol “ME”. Our common stock began trading regular way on March 3, 2006, following the consummation of our merger with Forest Energy Resources.
The high and low sales prices of our common stock on the NYSE during the period from March 3, 2006 through March 24, 2006 were $20.27 and $18.30, respectively.
As of March 17, 2006 there were 519 holders of record of the Company’s issued and outstanding common stock; we believe that there are significantly more beneficial holders of our stock.
We currently intend to retain our earnings for the development of our business and do not expect to pay any cash dividends. We have not paid any cash dividends for the fiscal years 2003, 2004 or 2005. See Item 7, ‘‘- Liquidity and Capital Resources - Credit Facility” and Item 8, Note 4 to Mariner’s Financial Statements for a discussion of certain covenants in our credit facility which restrict our ability to pay dividends.
See Item 11 for information relating to our equity compensation plans.
Recent Sales and Issuances of Unregistered Securities
In 2005 we sold and issued the following unregistered securities:
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On March 11, 2005, we issued 16,350,000 shares of our common stock in consideration of $212,877,000 before expenses to qualified institutional buyers, non-U.S. persons and accredited investors in transactions exempt from registration under Section 4(2) of the Securities Act. We paid Friedman, Billings, Ramsey & Co., Inc., who acted as placement agent in this transaction, $16,023,000 in discounts and placement fees. A selling stockholder in the offering paid an additional $10,035,200 in discounts and placement fees to Friedman, Billings, Ramsey & Co., Inc.
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On March 11, 2005, we issued 2,267,270 shares of restricted common stock to employees pursuant to our Equity Participation Plan. The issuance of these shares was exempt from the registration requirements of the Securities Act pursuant to Rule 701. See Item 11, “Equity Participation Plan.”
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During 2005, we issued options exercisable for an aggregate 809,000 shares of common stock to employees and directors pursuant to our Stock Incentive Plan as follows: options for an aggregate of 798,960 shares at $14.00 per share were issued on March 11, May 16, July 18 and July 25, 2005; options for an aggregate of 9,000 shares at $15.50 per share were issued on August 11, 2005; and an option for 1,040 shares at $17.00 per share was issued on September 19, 2005. The issuance of those options was exempt from the registration requirements of the Securities Act pursuant to Rule 701. These options generally vest and become exercisable in one-third increments on the first three anniversaries of the grant date (or, in the case of directors, on the first three annual stockholder meeting dates following grant), subject to acceleration in certain instances, including for employee options when the deemed change of control occurred upon the merger with Forest Energy Resources on March 2, 2006, whereupon options for an aggregate of 216,000 shares held by non-executive employees fully vested. Mariner’s executive officers waived accelerated vesting of their options for an aggregate of
584,000 shares. See Item 11, “Executive Compensation - Employment Agreements and Other Arrangements” and “- Amended and Restated Stock Incentive Plan.”
The registration statement on Form S-1 (SEC File No. 333-124858), as amended, filed by Mariner was declared effective by the SEC on February 10, 2006. Mariner registered for sale 33,348,130 shares of common stock, all of which were held by selling stockholders named in the registration statement. Under the registration statement, the shares can be offered and sold by the selling stockholders in one or more transactions at fixed prices, prevailing market prices or negotiated prices. There was no underwriter for the offering. Mariner did not sell any shares for our own account, and did not and will not receive any proceeds from the sale of securities by any selling stockholders. Mariner incurred expenses as detailed in the registration statement of approximately $1.9 million, none of which were direct or indirect payments to directors, officers or general partners of Mariner or their associates, or to persons owning 10% or more of any class of equity securities of Mariner.
Item 6.
Item 6.
Selected Financial Data.
The following table shows Mariner’s historical consolidated financial data as of and for the year ended December 31, 2005, the period from January 1, 2004 through March 2, 2004, the period from March 3, 2004 through December 31, 2004, and each of the three years ended December 31, 2003. The historical consolidated financial data as of and for the year ended December 31, 2005, the period from January 1, 2004 through March 2, 2004, the period from March 3, 2004 through December 31, 2004 and the year ended December 31, 2003, are derived from Mariner’s audited financial statements included herein, and the historical consolidated financial data as of and for the two years ended December 31, 2002 are derived from Mariner’s audited financial statements that are not included herein. You should read the following data in connection with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the consolidated financial statements included in Item 8, where there is additional disclosure regarding the information in the following table. Mariner’s historical results are not necessarily indicative of results to be expected in future periods.
On March 2, 2004, Mariner’s former indirect parent, Mariner Energy LLC, merged with MEI Acquisitions, LLC, an affiliate of the private equity funds, Carlyle/Riverstone Global Energy and Power Fund II, L.P. and ACON Investments LLC. The financial information contained herein is presented in the style of Post-2004 Merger activity (for the March 3, 2004 through December 31, 2004 period and the year ended December 31, 2005) and Pre-2004 Merger activity (for all periods prior to March 2, 2004) to reflect the impact of the restatement of assets and liabilities to fair value as required by “push-down” purchase accounting at the March 2, 2004 merger date.
(1)
Includes effects of hedging.
(1)
Balance sheet data as of December 31, 2004 reflects purchase accounting adjustments to oil and gas properties, total assets and stockholders’ equity resulting from the acquisition of our former indirect parent on March 2, 2004.
(2)
Working capital (deficit) excludes current derivative assets and liabilities, deferred tax assets and restricted cash.
(1)
EBITDA means earnings before interest, income taxes, depreciation, depletion and amortization and impairments. For the year ended December 31, 2005, EBITDA includes $25.7 million in non-cash stock compensation expense related to restricted stock and stock options granted in 2005. We believe that EBITDA is a widely accepted financial indicator that provides additional information about our ability to meet our future requirements for debt service, capital expenditures and working capital, but EBITDA should not be considered in isolation or as a substitute for net income, operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with generally accepted accounting principles or as a measure of a company’s profitability or liquidity.
(2)
In accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137 and No. 138, we de-designated our contracts effective December 2, 2001 after the counterparty (an affiliate of Enron Corp.) filed for bankruptcy and recognized all market value changes subsequent to such de-designation in our earnings. The value recorded up to the time of de-designation and included in Accumulated Other Comprehensive Income (“AOCI”), has reversed out of AOCI and into earnings as the original corresponding production, as hedged by the contracts, is produced. We have designated subsequent hedge contracts as cash flow hedges with gains and losses resulting from the transactions recorded at market value in AOCI, as appropriate, until recognized as operating income in our Statement of Operations as the physical production hedged by the contracts is delivered.
Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Overview
We are an independent oil and natural gas exploration, development and production company with principal operations in the Gulf of Mexico and the Permian Basin in West Texas. In the Gulf of Mexico, our areas of operation include the deepwater and the shelf area. We have been active in the Gulf of Mexico and West Texas since the mid-1980s. As a result of increased drilling of shelf prospects, the acquisition of Forest’s offshore Gulf of Mexico assets located primarily on the shelf, and development activities in the West Texas Permian Basin, we have evolved from a company with primarily a deepwater focus to one with a balance of exploitation and exploration of the Gulf of Mexico deepwater and shelf, and longer-lived West Texas Permian Basin properties.
On March 2, 2004, Mariner’s former indirect parent, Mariner Energy LLC, merged with MEI Acquisitions, LLC, an affiliate of the private equity funds, Carlyle/Riverstone Global Energy and Power Fund II, L.P. and ACON Investments LLC. Prior to the merger, we were owned indirectly by JEDI, which was an indirect wholly-owned subsidiary of Enron Corp. The gross merger consideration was $271.1 million (which excludes $7.0 million of acquisition costs and other expenses paid directly by Mariner), $100 million of which was provided as equity by our new owners. As a result of the merger, we are no longer affiliated with Enron Corp. See “-Enron Related Matters” under Item 1. The merger did not result in a change in our strategic direction or operations. The financial information contained herein is presented in the style of Pre-2004 Merger activity (for all periods prior to March 2, 2004) and Post-2004 Merger activity (for the March 3, 2004 through December 31, 2004 period) to reflect the impact of the restatement of assets and liabilities to fair value as required by “push-down” purchase accounting at the March 2, 2004 merger date. The application of push-down accounting had no effect on our 2004 results of operations other than immaterial increases in depreciation, depletion and amortization expense and interest expense and a related decrease in our provision for income taxes. To facilitate management’s discussion and analysis of financial condition and results of operations, we have presented 2004 financial information as Pre-2004 Merger (for the January 1 through March 2, 2004 period), Post-2004 Merger (for the March 3, 2004 through December 31, 2004 period) and Combined (for the full period from January 1 through December 31, 2004). The combined presentation does not reflect the adjustments to our statement of operations that would be reflected in a pro forma presentation. However, because such adjustments are not material, we believe that our combined presentation presents a fair presentation and facilitates an understanding of our results of operations.
In March 2005, we completed a private placement of 16,350,000 shares of our common stock to qualified institutional buyers, non-U.S. persons and accredited investors, which generated approximately $229 million of gross proceeds, or approximately $211 million net of initial purchaser’s discount, placement fee and offering expenses. Our former sole stockholder, MEI Acquisitions Holdings, LLC, also sold 15,102,500 shares of our common stock in the private placement. We used $166 million of the net proceeds from the sale of 12,750,000 shares of common stock to purchase and retire an equal number of shares of our common stock from our former sole stockholder. We used $38 million of the remaining net proceeds of approximately $44 million to repay borrowings drawn on our credit facility, and the balance to pay down $6 million of a $10 million promissory note payable to JEDI. See “-Enron Related Matters” under Item 1. As a result, after the private placement, an affiliate of MEI Acquisitions Holdings, LLC beneficially owned approximately 5.3% of our outstanding common stock.
Our revenues, profitability and future growth depend substantially on prevailing prices for oil and gas and our ability to find, develop and acquire oil and gas reserves that are economically recoverable while controlling and reducing costs. The energy markets have historically been very volatile. Commodity prices are currently at or near historical highs and may fluctuate and decline significantly in the future. Although we attempt to mitigate the impact of price declines through our hedging strategy, a substantial or extended decline in oil and natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of natural gas and oil reserves that we can economically produce and our access to capital.
Recent Developments
On March 2, 2006, we completed a merger transaction with Forest Energy Resources. Prior to the consummation of the merger, Forest transferred and contributed the assets and certain liabilities associated with its offshore Gulf of Mexico operations to Forest Energy Resources. Immediately prior to the merger, Forest distributed all of the outstanding shares of Forest Energy Resources to Forest shareholders on a pro rata basis. Forest Energy Resources then merged with a newly formed subsidiary of Mariner, and become a new wholly owned subsidiary of Mariner. Upon the merger, approximately 59% of the Mariner common stock was held by shareholders of Forest and approximately 41% of Mariner common stock was held by the pre-merger stockholders of Mariner. Our acquisition of Forest Energy Resources added approximately 306.1 Bcfe of estimated proved reserves as of December 31, 2005, of which approximately 76% were natural gas and 24% were oil and condensate and natural gas liquids. As of December 31, 2005, the standardized measure of discounted future net cash flows attributable to Forest Energy Resources estimated proved reserves was approximately $1.3 billion. Please see “- Estimated Proved Reserves” in Items 1 and 2 for a discussion of our calculation of the standardized measure of discounted future net cash flows.
In 2005 our operations were adversely affected by one of the most active and severe hurricane seasons in recorded history. As of December 31, 2005, we had approximately 5 MMcfe per day of net production shut-in as a result of Hurricanes Katrina and Rita, and approximately 56 MMcfe per day on a pro forma basis. We estimate that as of March 15, 2006 approximately 42 MMcfe per day remains shut in. Additionally, we experienced delays in startup of four of our deepwater projects primarily as a result of Hurricane Katrina. Two of the projects have commenced production, and two are anticipated to commence production in the second quarter of 2006. For the period September through December 2005, we estimate that approximately 6-8 Bcfe of production (approximately 15-20 Bcfe on a pro forma basis) was deferred because of the hurricanes. We also estimate that an additional 8 Bcfe of production will be deferred in 2006 before repairs to offshore and onshore infrastructure are fully completed, allowing return of full production from our fields. However, the actual volumes deferred in 2006 will vary based on circumstances beyond our control, including the timing of repairs to both onshore and offshore platforms, pipelines and facilities, the actions of operators on our fields, availability of service equipment, and weather.
We estimate the costs to repair damage caused by the hurricanes to our platforms and facilities will total approximately $50 million. However, until we are able to complete all the repair work this estimate is subject to significant variance. For the insurance period covering the 2005 hurricane activity, we carried a $3 million annual deductible and a $0.5 million single occurrence deductible for the Mariner assets. Insurance covering the Forest Gulf of Mexico properties carried a $5 million deductible for each occurrence. Until the repairs are completed and we submit costs to our insurance underwriters for review, the full extent of our insurance recoveries and the resulting net cost to us for Hurricanes Katrina and Rita will be unknown. However, we expect the total costs not covered by the combined insurance policies to be less than $15 million.
We entered into an agreement effective in October 2005 covering approximately 33,000 acres in West Texas, pursuant to which, upon closing, we acquired an approximate 35% working interest in approximately 200 existing producing wells effective November 1, 2005, and committed to drill an additional 150 wells within a four year period, funding $36.5 million of our partner’s share of drilling costs for such 150-well drilling program. We will obtain an assignment of an approximate 35% working interest in the entire committed acreage upon completion of the 150-well drilling program.
Highlights
During the year ended December 31, 2005, we recognized net income of $40.5 million on total revenues of $199.7 million compared to net income of $68.4 million on total revenues of $214.2 million in 2004. Net income decreased 41% compared to 2004, primarily due to recognizing $25.7 million of stock compensation expense in 2005, and a 23% decrease in production, partially offset by a 35% improvement in net commodity prices realized by us (before the effects of hedging.) Our 2005 results were also negatively impacted by increased hedging losses of $49.3 million in 2005 compared to a $19.8 million loss in 2004. We produced approximately 29.1 Bcfe during 2005 and our average daily production rate was 80 MMcfe compared to
37.6 Bcfe, or 103 MMcfe per day, for 2004. Production during the last two quarters of 2005 was negatively impacted by the effects of the 2005 hurricane season. We invested approximately $252.7 million in total capital in 2005 compared to $148.9 million in 2004.
Our 2005 results reflect the private placement of an additional 3.6 million shares of stock in March 2005. The net proceeds of approximately $44 million generated by the private placement were used to repay existing debt. We also granted 2,267,270 shares of restricted stock and options to purchase 809,000 shares of stock in 2005 and recorded compensation expense of $25.7 million in 2005 related to the restricted stock and options.
Highlights
We recognized net income of $68.4 million in 2004 compared to net income of $38.2 million in 2003. The increase in net income was primarily the result of improvements in operating results, including a 13% increase in production volumes, a 21% improvement in the net commodity prices realized by us (before the effects of hedging) and an 8% decrease in lease operating expenses and transportation expenses on a per unit basis. These improvements were partially offset by an 8% increase in general and administrative expenses and a 34% increase in depreciation, depletion, and amortization expenses. Our hedging results also improved by $9.7 million to a $19.8 million loss, from a $29.5 million loss in the prior year. In addition, we recorded income tax expenses of $36.9 million in 2004 compared to $9.4 million in 2003.
We have incurred and expect to continue to incur substantial capital expenditures. However, for the three years ended December 31, 2004, our capital expenditures of $337.3 million were below our combined cash flow from operations and proceeds from property sales.
During 2004, we increased our proved reserves by approximately 69 Bcfe, bringing estimated proved reserves as of December 31, 2004 to approximately 237.5 Bcfe after 2004 production of 37.6 Bcfe.
We had $2.5 million and $60.2 million in cash and cash equivalents as of December 31, 2004 and December 31, 2003, respectively.
Production
Our production for 2005 averaged approximately 50 MMcf of natural gas per day and approximately 4,900 barrels of oil per day, or a total of approximately 80 MMcfe per day. Natural gas production comprised approximately 63% of total production in 2005 and 2004.
In the last two quarters of 2005 our production was negatively impacted by Hurricanes Katrina and Rita. Production shut-in and deferred because of the hurricanes’ impact totaled approximately 6-8 Bcfe during the last two quarters of 2005. As of December 31, 2005 approximately 5 MMcfe per day of production remained shut-in awaiting repairs, primarily associated with our Baccarat property, which was brought back on-line in January 2006. While we believe physical damage to our existing platforms and facilities was relatively minor from both hurricanes, the effects of the storms caused damage to onshore pipeline and processing facilities that resulted in a portion of our production being temporarily shut-in, or in the case of our Viosca Knoll 917 (Swordfish) project, postponed until the fourth quarter of 2005. In addition, Hurricane Katrina caused damage to platforms that host three of our development projects: Mississippi Canyon 718 (Pluto), Mississippi Canyon 296 (Rigel), and Mississippi Canyon 66 (Ochre). Production on our Rigel project commenced in the first quarter of 2006. We expect production on the two remaining projects to recommence in the second quarter of 2006.
Our December 2004 total production averaged approximately 58 MMcf of natural gas per day and approximately 5,700 barrels of oil per day or total equivalents of approximately 92 MMcfe per day. In September 2004, Mariner incurred damage from Hurricane Ivan that affected our Mississippi Canyon 66 (Ochre) and Mississippi Canyon 357 fields. Production from Mississippi Canyon 357 was shut-in until March 2005, when necessary repairs were completed and production recommenced. Production from Mississippi Canyon 66 (Ochre) remains shut-in and is expected to recommence in the second quarter of 2006. This field was producing at a net rate of approximately 6.5 MMcfe per day immediately prior to the hurricane.
Historically, a majority of our total production has been comprised of natural gas. We anticipate that our concentration in natural gas production will continue. As a result, Mariner’s revenues, profitability and cash flows will be more sensitive to natural gas prices than to oil and condensate prices.
Generally, our producing properties in the Gulf of Mexico will have high initial production rates followed by steep declines. As a result, we must continually drill for and develop new oil and gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find and develop these reserves. Our challenge is to find and develop reserves at economic rates and commence production of these reserves as quickly and efficiently as possible.
Deepwater discoveries typically require a longer lead time to bring to productive status. Since 2001, we have made several deepwater discoveries that are in various stages of development. We commenced production at our Green Canyon 178 (Baccarat) project in the third quarter of 2005. However, damage sustained by the host facility during Hurricane Rita caused production to be shut-in. Production recommenced in January 2006. We commenced production at our Swordfish project in the fourth quarter of 2005 and at our Rigel project in the first quarter of 2006. We currently anticipate commencing production in the second quarter of 2006 at our Pluto and Ewing Banks 921 (North Black Widow) projects. However, as described above, Hurricanes Katrina and Rita have delayed start-up of these projects from their original anticipated commencement dates. Other uncertainties, including scheduling, weather, and construction lead times, could cause further delays in the start-up of any one or all of the projects.
Oil and Gas Property Costs
In 2005, we incurred approximately $242.6 million in capital costs related to property acquisitions, exploration, and development activities and approximately $10.1 million for capital costs associated with the installation of our Aldwell unit gathering system and other minor corporate items. Of the total $252.7 million of capital expenditures incurred in 2005, approximately 51% related to development activities and capitalized overhead and interest, 24% for exploration activities, including the acquisition of leasehold and seismic, 21% for property acquisitions, and the balance was associated with the Aldwell Unit gathering system and minor corporate items. Of the $121.7 million incurred on development activities and capitalized overhead and interest, approximately 27% were for onshore operations, 69% for deep water operations, and 4% for shallow Gulf of Mexico operations. Expenditures for property acquisitions included $46.1 million for assets located in the West Texas Permian Basin and $7.9 million to acquire additional interests in offshore Gulf of Mexico projects.
During 2004, we incurred approximately $148.9 million in capital expenditures with 60% related to development activities, 32% related to exploration activities, including the acquisition of leasehold and seismic, and the remainder related to acquisitions and other items (primarily capitalized overhead and interest). We spent approximately $88.6 million in development capital expenditures in 2004 primarily on Aldwell Unit development and for Viosca Knoll 917 (Swordfish), Mississippi Canyon 718 (Pluto), and West Cameron 333 (Royal Flush) offshore projects. All capital expenditures for exploration activities relate to offshore projects, and approximately 30% of exploration capital expended during 2004 was for leasehold, seismic, and geological and geophysical costs. During 2004 we participated in fourteen exploration wells, with seven being successful. We incurred approximately $47.9 million of exploration capital expenditures in 2004.
Oil and Gas Reserves
We have maintained our reserve base through exploration and exploitation activities despite selling 44.4 Bcfe of our reserves in 2002. Historically, we have not acquired significant reserves through acquisition activities; however, in 2005, we acquired 93.9 Bcfe of estimated proved reserves primarily in the West Texas Permian Basin area. In March 2006, we acquired estimated proved reserves of 306.1 Bcfe as a result of the merger with Forest Energy Resources. As of December 31, 2005, Ryder Scott estimated our net proved reserves at approximately 337.6 Bcfe, with a PV10 of approximately $1.3 billion and a standardized measure of discounted future net cash flows attributable to our estimated proved reserves of approximately $906.6 million. Please see “-Estimated Proved Reserves” under Item 1 for a definition of PV10 and a
reconciliation of PV10 to the standardized measure of discounted future net cash flows and for more information concerning our reserve estimates.
The development and acquisitions in the West Texas Permian Basin area and Gulf of Mexico deepwater divestitures have significantly changed our reserve profile since 2002. Proved reserves as of December 31, 2005 were comprised of 61% West Texas Permian Basin, 6% Gulf of Mexico shelf and 33% Gulf of Mexico deepwater compared to 33% West Texas Permian Basin, 19% Gulf of Mexico shelf and 48% Gulf of Mexico deepwater as of December 31, 2002. Proved undeveloped reserves were approximately 50% of total proved reserves as of December 31, 2005. Approximately 25% of proved undeveloped reserves were related to our West Texas Aldwell Unit, where we had 100% development drilling success on 170 wells from 2002 through 2005.
Since December 31, 1997, we have added proved undeveloped reserves attributable to 12 deepwater projects. As of December 31, 2005, ten of those projects have either been converted to proved developed reserves or sold as indicated in the following table.
(1)
Net proved undeveloped reserves attributable to the project in the year it was first added to our proved reserves.
(2)
This field was shut-in in April 2004 pending the drilling of a new well and installation of an extension to the existing infield flowline and umbilical. As a result, as of December 31, 2005, 8.9 Bcfe of our net proved reserves attributable to this project were classified as proved behind pipe reserves. We expect production from Pluto to recommence in the second quarter of 2006.
The proved undeveloped reserves attributable to the remaining two deepwater projects were added as follows:
(1)
Net proved undeveloped reserves attributable to the project as of December 31, 2005.
Oil and Natural Gas Prices and Hedging Activities
Prices for oil and natural gas can fluctuate widely, thereby affecting the amount of cash flow available for capital expenditures, our ability to borrow and raise additional capital and the amount of oil and natural gas that we can economically produce. Recently, oil and natural gas prices have been at or near historical highs and very volatile as a result of various factors, including weather, industrial demand, war and political instability and uncertainty related to the ability of the energy industry to provide supply to meet future demand.
Our revenues, profitability and future growth depend substantially on prevailing prices for oil and gas and our ability to find, develop and acquire oil and gas reserves that are economically recoverable while controlling and reducing costs. A substantial or extended decline in oil and natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that we can economically produce and access to capital.
We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices. Typically, our hedging strategy involves entering into commodity price swap arrangements and costless collars with third parties. Price swap arrangements establish a fixed price and an index-related price for the covered commodity. When the index-related price exceeds the fixed price, we pay the third party the difference, and when the fixed price exceeds the index-related prices, the third party pays us the difference. Costless collars establish fixed cap (maximum) and floor (minimum) prices as well as an index-related price for the covered commodity. When the index-related price exceeds the fixed cap price, we pay the third party the difference, and when the index-related price is less than the fixed floor price, the third party pays us the difference. While our hedging arrangements enable us to achieve a more predictable cash flow, these arrangements also limit the benefits of increased prices. As a result of increased oil and natural gas prices, we incurred cash hedging losses of $53.8 million in 2005, of which $4.5 million relates to the hedge liability recorded at the March 2, 2004 merger date. Major challenges related to our hedging activities include a determination of the proper production volumes to hedge and acceptable commodity price levels for each hedge transaction. Our hedging activities may also require that we post cash collateral with our counterparties from time to time to cover credit risk. We had no collateral requirements as of December 31, 2005 or December 31, 2004.
In accordance with purchase price accounting implemented at the time of the merger of our former indirect parent company on March 2, 2004, we recorded the mark-to-market liability of our hedge contracts at such date totaling $12.4 million as a liability on our balance sheet. As of December 31, 2005, the amount of our mark-to-market hedge liabilities totaled $63.8 million. See “-Liquidity and Capital Resources-Commodity Prices and Related Hedging Activities.”
For the year ended December 31, 2005, assuming a totally unhedged position, our price sensitivity for 2005 net revenues for a 10% change in average oil prices and average gas prices received is approximately $9.3 million and $15.3 million, respectively. For the year ended December 31, 2004, assuming a totally unhedged position, our price sensitivity for 2004 historical net revenues for a 10% change in average oil prices and average gas prices received is approximately $8.9 million and $14.5 million, respectively.
Operating Costs
We classify our operating costs as lease operating expense, transportation expense, and general and administrative expenses. Lease operating expenses are comprised of those costs and expenses necessary to produce oil and gas after an individual well or field has been completed and prepared for production. These costs include direct costs such as field operations, general maintenance expenses, work-overs, and the costs associated with production handling agreements for most of our deep water fields. Lease operating expenses also include indirect costs such as oil and gas property insurance and overhead allocations in accordance with joint operating agreements. We also include severance, production, and ad valorem taxes as lease operating expenses.
Transportation costs are generally variable costs associated with transportation of product to sales meters from the wellhead or field gathering point. General and administrative include employee compensation costs (including stock compensation expense), the costs of third party consultants and professionals, rent and other costs of leasing and maintaining office space, the costs of maintaining computer hardware and software, and insurance and other items.
Critical Accounting Policies and Estimates
Our discussion and analysis of Mariner’s financial condition and results of operations are based upon financial statements that have been prepared in accordance with GAAP in the U.S. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 1 to our financial statements. We analyze our estimates, including those related to oil and gas revenues, oil and gas properties, fair value of derivative instruments, income taxes and contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements:
Oil and Gas Properties
Oil and gas properties are accounted for using the full-cost method of accounting. All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and gas properties are capitalized. Amortization of oil and gas properties is provided using the unit-of-production method based on estimated proved oil and gas reserves. No gains or losses are recognized upon the sale or disposition of oil and gas properties unless the sale or disposition represents a significant quantity of oil and gas reserves, which would have a significant impact on depreciation, depletion and amortization. The net carrying value of proved oil and gas properties is limited to an estimate of the future net revenues (discounted at 10%) from proved oil and gas reserves based on period-end prices and costs.
The costs of unproved properties are excluded from amortization using the full-cost method of accounting. These costs are assessed quarterly for possible inclusion in the full-cost property pool based on geological and geophysical data. If a reduction in value has occurred, costs being amortized are increased. The majority of the costs relating to our unproved properties will be evaluated over the next three years.
Proved Reserves
Our most significant financial estimates are based on estimates of proved natural gas and oil reserves. Estimates of proved reserves are key components of our unevaluated properties, our rate for recording depreciation, depletion and amortization and our full cost ceiling limitation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond our control. The estimation process relies on assumptions and interpretations of available geologic, geophysical, engineering and production data, and the accuracy of reserve estimates is a function of the quality and quantity of available data. Our reserves are fully engineered on an annual basis by Ryder Scott.
Compensation Expense
As a result of the adoption of SFAS Statement No. 123(R), we recorded compensation expense for the fair value of restricted stock and stock options that were granted on March 11, 2005 pursuant to our Equity Participation Plan and Stock Incentive Plan and for the fair value of subsequent grants of stock options or restricted stock made pursuant to our Stock Incentive Plan. In general, compensation expense will be determined at the date of grant based on the fair value of the stock or options granted.
The fair value of restricted stock that we granted following the closing of the private equity placement pursuant to our Equity Participation Plan was estimated to be $31.7 million. The fair value will be amortized to compensation expense over the applicable vesting periods. Stock options and restricted stock granted under our Stock Incentive Plan will also result in recognition of compensation expense in accordance with FASB No. 123(R).
Revenue Recognition
We use the entitlements method of accounting for the recognition of natural gas and oil revenues. Under this method of accounting, income is recorded based on our net revenue interest in production or nominated deliveries. We incur production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over-and-under deliveries or by cash settlement, as required by applicable contracts. Production imbalances are marked-to-market at the end of each month at the lowest of (i) the price in effect at the time of production; (ii) the current market price; or (iii) the contract price, if a contract is in hand.
The Company’s gas balancing assets and liabilities are not material as oil and gas volumes sold are not significantly different from the Company’s share of production.
Income Taxes
Our taxable income through 2004 has been included in a consolidated U.S. income tax return with our former indirect parent company, Mariner Energy LLC. The intercompany tax allocation policy provides that each member of the consolidated group compute a provision for income taxes on a separate return basis. We record income taxes using an asset and liability approach which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax bases of assets and liabilities. Valuation allowances are established when necessary to reduce deferred tax assets to the amount more likely than not to be recovered. In February 2005, Mariner Energy LLC was merged into us, and we will file our own income tax return following the effective date of that merger.
Accrual for Future Abandonment Costs
SFAS No. 143, “Accounting for Asset Retirement Obligations,” addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
Hedging Program
In June 1998 the FASB issued SFAS No. 133, “Accounting for Derivative Instruments and Certain Hedging Activities.” In June 2000 the FASB issued SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activity, an Amendment of SFAS No. 133.” SFAS No. 133 and SFAS No. 138 require that all derivative instruments be recorded on the balance sheet at their respective fair values.
Mariner utilizes derivative instruments, typically in the form of natural gas and crude oil price swap agreements and costless collar arrangements, in order to manage price risk associated with future crude oil and natural gas production. These agreements are accounted for as cash flow hedges. Gains and losses resulting from these transactions are recorded at fair market value and deferred to the extent such amounts are effective. Such gains or losses are recorded in Accumulated Other Comprehensive Income (“AOCI”) as appropriate, until recognized as operating income as the physical production hedged by the contracts is delivered.
The net cash flows related to any recognized gains or losses associated with these hedges are reported as oil and gas revenues and presented in cash flows from operations. If the hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period as the physical production hedged by the contracts is delivered.
The conditions to be met for a derivative instrument to qualify as a cash flow hedge are the following: (i) the item to be hedged exposes Mariner to price risk; (ii) the derivative reduces the risk exposure and is designated as a hedge at the time the derivative contract is entered into; and (iii) at the inception of the hedge and throughout the hedge period there is a high correlation of changes in the market value of the derivative instrument and the fair value of the underlying item being hedged.
When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on sale or settlement of the underlying item. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if correlation no longer exists, the gain or loss on the derivative is recognized in income to the extent the future results have not been offset by the effects of price or interest rate changes on the hedged item since the inception of the hedge.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from these estimates.
Results of Operations
For certain information with respect to our oil and natural gas production, average sales price received and expenses per unit of production for the three years ended December 31, 2005, see “-Production” under Item 1.
Year Ended December 31, 2005 compared to Year Ended December 31, 2004
Operating and Financial Results for the Year Ended December 31,
Compared to the Year Ended December 31, 2004
(1)
Average realized prices include the effects of hedges.
Net production during 2005 decreased approximately 23% to 29.1 Bcfe from 37.6 Bcfe in 2004 primarily due to decreased Gulf of Mexico production, partially offset by increased onshore production. Mariner’s production was negatively impacted during the third and fourth quarters of 2005 due to hurricane activity, primarily Katrina and Rita. Production shut-in and deferred because of the hurricanes’ impact totaled approximately 6-8 Bcfe during the third and fourth quarters of 2005. As of December 31, 2005, approximately 5 MMcfe per day of production remained shut-in awaiting repairs, primarily associated with our Baccarat property (although, production therefrom recommenced in January 2006). Additionally, production that was anticipated to commence in 2005 at our Swordfish, Pluto, and Rigel development projects was delayed awaiting repairs to host facilities. Swordfish recommenced production in the fourth quarter of 2005 and Rigel recommenced production in the first quarter of 2006. Ochre and Pluto are expected to commence production in the second quarter of 2006.
Increased development drilling at our Aldwell unit in West Texas contributed to a 60% increase in onshore production to an average of approximately 18.1 MMcfe per day in 2005 from an average of approximately 11.3 MMcfe per day in 2004.
In the deepwater Gulf of Mexico, production decreased approximately 32% to an average of approximately 32.3 MMcfe per day in 2005 compared to an average of approximately 47.2 MMcfe per day in 2004. The decrease was largely due to reduced production at our Black Widow, Yosemite and Pluto fields. Pluto was shut-in in April 2004 pending drilling of the new Mississippi Canyon 674 #3 well and installation of an extension to the existing subsea facilities. Production at Black Widow and Yosemite was negatively impacted by hurricane activity as well as by expected declines. As previously discussed, hurricane-related delays in commencement of production at our Swordfish, Pluto and Rigel development projects also contributed to the production decline.
In the Gulf of Mexico shelf, production decreased by approximately 34% to an average of approximately 29.2 MMcfe per day in 2005 from an average of approximately 44.1 MMcfe per day in 2004. About 6.2 MMcfe per day of the decrease is attributable to our Ochre field, which remains shut-in due to the effects of Hurricane Ivan in September 2004 and Hurricanes Katrina and Rita in 2005. Production from three new shelf discoveries (Green Pepper, Royal Flush, and Dice) and production from the 2004 acquisition of interests in five offshore fields offset normal declines at our other Gulf of Mexico shelf fields and the impact of the 2005 hurricane season.
Hedging activities in 2005 decreased our average realized natural gas price received by $1.67 per Mcf and revenues by $30.6 million, compared with a decrease of $0.32 per Mcf and revenues of $7.5 million in 2004. Our hedging activities with respect to crude oil during 2005 decreased the average sales price received by $10.43 per barrel and revenues by $18.7 million compared with a decrease of $5.35 per barrel and revenues of $12.3 million for 2004.
Oil and gas revenues decreased 8% to $196.1 million in 2005 when compared to 2004 oil and gas revenues of $214.2 million, due to the aforementioned 23% decrease in production, partially offset by an 18% increase in realized prices (including the effects of hedging) to $6.74 per Mcfe in 2005 from $5.70 per Mcfe in 2004.
Other revenues of $3.6 million in 2005 represent an indemnity payment of $1.9 million received from our former stockholder related to the merger and $1.7 million generated by our West Texas Aldwell unit gathering system.
Lease operating expenses increased 17% to $29.9 million in 2005 from $25.5 million in 2004. The increased costs were primarily attributable to the addition of new producing wells at our Aldwell Unit offset by reduced costs on our Black Widow, King Kong/Yosemite, and Pluto deepwater fields. On a per unit basis, lease operating expenses were $1.03 per Mcfe in 2005 compared to $0.68 per Mcfe in 2004. The increased per unit costs also reflect lower production rates in 2005, including hurricane-related disruptions.
Transportation expenses were $2.3 million or $0.08 per Mcfe in 2005, compared to $3.0 million or $0.08 per Mcfe in 2004. The reduction is primarily attributable to our deepwater fields and includes reductions caused by the filing of new and higher transportation allowances with the MMS on two of our deepwater fields for purpose of royalty calculation.
Depreciation, depletion, and amortization (“DD&A”) expense decreased 8% to $59.4 million during 2005 from $64.9 million for 2004 as a result of decreased production of 8.5 Bcfe in 2005 compared to 2004, partially offset by an increase in the unit-of-production depreciation, depletion and amortization rate to $2.04 per Mcfe for 2005 from $1.73 per Mcfe for 2004. The per unit increase was primarily the result of an increase in future development costs on our deepwater development fields.
General and administrative (“G&A”) expenses, which are net of $6.9 million and $4.4 million of overhead reimbursements billed or received from other working interest owners in 2005 and 2004, respectively, increased 322% to $37.1 million during 2005 compared to $8.8 million in 2004. The increase was primarily due to recognizing $25.7 million in stock compensation expense related to restricted stock and options granted in 2005. We also paid $2.3 million to our former stockholders to terminate a services agreement in 2005, compared to $1.0 million under the same agreement in 2004. In addition, G&A expenses increased by $1.6 million due to a reduction in the amount of G&A capitalized in 2005 compared to 2004.
Impairment of production equipment held for use reflects the reduction of the carrying cost of our inventory by $1.8 million and $1.0 million as of December 31, 2005 and December 31, 2004, respectively. In 2005, the reduction in estimated value primarily related to subsea trees and wellhead equipment held in inventory.
Net interest expense for 2005 increased 25% to $7.4 million from $5.7 million in 2004, primarily due to higher average debt levels in 2005 compared to 2004. In connection with the merger on March 2, 2004, Mariner incurred $135 million in new bank debt and issued a $10 million promissory note to JEDI. For comparison purposes, approximately ten months of interest related to such borrowings is reflected in 2004 compared to twelve months of interest in 2005.
Income before income taxes decreased to $61.8 million for 2005 compared to $105.3 million for 2004, attributable primarily to the decrease in oil and gas revenues resulting from the decreased production and increased G&A expenses, both as noted above. Offsetting these factors were the receipt of other income related to the indemnity payment and lower DD&A and transportation expenses.
Provision for income taxes decreased to $21.3 million for 2005 from $36.9 million for 2004 as a result of decreased operating income for 2005 compared to 2004.
Year Ended December 31, 2004 compared to Year Ended December 31, 2003
Operating and Financial Results for the Year Ended December 31,
Compared to the Year Ended December 31, 2003
(1)
Average realized prices include the effects of hedges.
Net production during 2004 increased to 37.6 Bcfe from 33.4 Bcfe during 2003 primarily due to the commencement of production on our Roaring Fork and Ochre projects, offset by normal production declines on existing fields.
Hedging activities in 2004 decreased our average realized natural gas price received by $0.32 per Mcf and revenues by $7.5 million, compared with a decrease of $1.03 per Mcf and revenues of $24.5 million for 2003. Our hedging activities with respect to crude oil during 2004 decreased the average sales price received by $5.35 per bbl and revenues by $12.3 million compared with a decrease of $3.11 per bbl and revenues of $5.0 million for 2003.
Oil and gas revenues increased 50% to $214.2 million during 2004 when compared to 2003 oil and gas revenues of $142.5 million, due to a 13% increase in production and a 33% increase in realized prices (including the effects of hedging) to $5.70 per Mcfe in 2004 from $4.27 per Mcfe in 2003.
Lease operating expenses increased 3% to $25.5 million in 2004 from $24.7 million in 2003 due to increased activity in our West Texas Aldwell project, partially offset by lower compression costs on our King Kong and Yosemite projects and the shut-in of our Pluto project for a large portion of 2004 pending the drilling and completion of the Mississippi Canyon 674 No. 3 well, which has been drilled and awaits installation of flowlines and related facilities.
Transportation expenses were $3.0 million for 2004, compared to $6.3 million for 2003. In the fourth quarter of 2004, we filed new transportation allowances with the MMS for purpose of royalty calculation. This resulted in a $3.2 million decrease in transportation expense in 2004 compared to 2003. In addition, transportation expense from our new Roaring Fork field was offset by declines from our existing fields.
DD&A expense increased 34% to $64.9 million during 2004 from $48.3 million for 2003 as a result of an increase in the unit-of-production depreciation, depletion and amortization rate to $1.73 per Mcfe from $1.45 per Mcfe for the comparable period and a production increase of 4.2 Bcfe in 2004 compared to 2003. The per unit increase is primarily attributable to non-cash purchase accounting adjustments resulting from the merger.
G&A expenses, which are net of $4.4 million of overhead reimbursements received from other working interest owners, increased 8% to $8.8 million during 2004 compared to $8.1 million in 2003 primarily due to increased compensation costs paid in connection with the merger and payments made pursuant to services
contracts with affiliates of our sole stockholder, offset by increased overhead recoveries from our partners and amounts capitalized.
Impairment of production equipment held for use reflects the reduction of the carrying cost of our inventory as of December 31, 2004 by $1.0 million to account for a reduction in estimated value primarily related to subsea trees held in inventory.
Net interest expense for 2004 decreased 8% to $5.7 million from $6.2 million for 2003, primarily due to the repayment of our senior subordinated notes in August 2003, replaced by lower-cost bank debt in March 2004.
Income before income taxes and change in accounting method increased to $105.3 million for 2004 compared to $45.7 million in 2003, attributable primarily to the increase in oil and gas revenues resulting from the increased production and realized prices noted above.
Provision for income taxes increased to $36.9 million for 2004 from $9.4 million for 2003 as a result of increased current year operating income.
Liquidity and Capital Resources
Cash Flows and Liquidity
At December 31, 2005, we had $152 million in advances outstanding under our revolving credit facility with a borrowing base as of that date of $170 million. In January 2006, the borrowing base was increased to $185 million. In connection with the merger with Forest Energy Resources on March 2, 2006, we amended and restated our existing credit facility to increase maximum credit availability to $500 million, with a $400 million borrowing base as of that date. On March 2, 2006, after giving effect to funds required at closing to refinance $176.2 million of debt assumed in the merger and other merger-related costs, our total debt drawn under the facility was approximately $350 million, including a $4.2 million letter of credit required for plugging and abandonment obligations at one of our offshore fields. In addition, we have established a $40 million letter of credit for the benefit of Forest Oil Corporation to guarantee certain drilling obligations in West Texas that is not included as a use of our borrowing base availability. The $4 million balance remaining on a note payable to JEDI at December 31, 2005 was repaid in full on its maturity date of March 2, 2006.
Working capital at December 31, 2005 was negative $46.4 million, excluding current derivative liabilities and deferred taxes. Accrued liabilities (including accounts payable) and accrued receivables (including accounts receivable) at December 31, 2005 increased by approximately 91% and 68%, respectively, over levels at December 31, 2004 primarily due to increased accrued obligations for drilling and development projects in progress at year end 2005 and related accruals of amounts owed by partners. As of December 31, 2004, we had negative working capital of approximately $18.7 million compared to positive working capital of $38.3 million at December 31, 2003, in each case excluding current derivative liabilities and restricted cash. The reduction in working capital from 2003 is primarily the result of a change in the manner Mariner utilizes excess cash. At year end 2003, Mariner operated with no debt and consequently accumulated cash (approximately $60 million at year end 2003) generated by operations and asset sales in order to fund future obligations and business activities. In March 2004, Mariner entered into a revolving credit facility, and since then has utilized excess cash to pay down outstanding advances to maintain debt levels as low as possible. In addition, our accounts payable and accrued liabilities at December 31, 2004 increased by about 32% over levels at December 31, 2003 primarily as a result of funding for development of our deepwater projects in progress at year end.
Our 2005 capital expenditures were $252.7 million. Approximately 48% of our capital expenditures were incurred for development projects, 24% for exploration activities, 21% for acquisitions of developed properties, and the remainder for other items (primarily expenditures for our Aldwell gathering system, capitalized overhead and interest).
We anticipate that our capital expenditures for 2006 will approximate $463.5 million with approximately 57% allocated to development activities, 41% to exploration activities, and the remainder to other items
(primarily capitalized overhead and interest). The 2006 budget is an increase of approximately 83% over our 2005 expenditures. The increase is primarily driven by the addition of the Forest Gulf of Mexico operations, continuation of our deepwater development activities, and expansion of our exploration activities, including increasing our acquisition of leasehold and seismic data. In addition, we expect to incur approximately $33 million for repairs of damage caused by Hurricanes Katrina and Rita in 2006. While this will be a cash outflow in 2006, we expect to recover these costs through insurance reimbursements later in 2006 or 2007. Since we believe these costs to be reimbursable, they will not be reflected in reported 2006 capital expenditures.
We believe our cash flows generated by operations will be sufficient to fund our anticipated capital expenditures. However, the effects of the 2005 hurricane season have reduced our anticipated cash flows coming into 2006 and some production continues to be deferred pending repairs to both offshore and onshore pipelines and facilities. We believe that by mid-year 2006 most of the production deferred by the 2005 hurricane season will be brought on-line. In addition, natural gas prices have weakened considerably in the first quarter of 2006 from 2005 levels. To the extent cash flows during 2006 are not sufficient to fund our capital obligations, we will utilize additional borrowings under our existing revolving credit facility. We currently have a borrowing base of $400 million with approximately $350 million utilized as of March 2, 2006.
In addition, we plan a high yield notes offering in the second quarter of 2006. The proceeds of this offering will be utilized to reduce borrowings under our revolving credit facility, which will provide additional liquidity. The notes would not be registered under the Securities Act or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from registration. We expect that the notes would be offered only to qualified institutional buyers under Rule 144A and non-U.S. persons under Regulation S. We anticipate that the terms of the notes would be no more restrictive than the terms of our credit facility.
The timing of expenditures (especially regarding deepwater projects) is unpredictable. Also, our cash flows are heavily dependent on the oil and natural gas commodity markets, and our ability to hedge oil and natural gas prices is limited by our revolving credit facility to no more than 80% of our expected production from proved developed producing reserves. If either oil or natural gas commodity prices decrease from their current levels, our ability to finance our planned capital expenditures could be affected negatively. Amounts available for borrowing under our revolving credit facility are largely dependent on our level of proved reserves and current oil and natural gas prices. Furthermore, we can provide no assurance that our planned high yield notes offering will be successful. If either our proved reserves or commodity prices decrease, amounts available to us to borrow under our revolving credit facility could be reduced. If our cash flows are less than anticipated or amounts available for borrowing under our revolving credit facility are reduced or we can not access the high yield or other debt markets, we may be forced to defer planned capital expenditures.
In addition, our future oil and natural gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our cash flows will be affected adversely. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves.
Our existing proved reserves are comprised of West Texas and Gulf of Mexico properties. The West Texas properties are relatively long-life in nature characterized by relatively low decline rates (lower productive rates) while the Gulf of Mexico properties are shorter-life in nature characterized by relatively high decline rates (higher productive rates). For the year ended December 31, 2005, our Gulf of Mexico properties comprised about 77% of our total production or 93% on a pro forma basis. We plan to maintain an active drilling program for our onshore properties with the intention of maintaining or increasing production in those
areas. Although production from our existing offshore wells will decline more rapidly over time than our onshore wells, the percentage of production attributable to our offshore wells is expected to increase in the coming years as more of our undeveloped deep water projects commence production and we begin to exploit our newly acquired offshore assets. While we expect this trend to continue for the near future, oil and gas production (especially for our offshore properties) can be heavily affected by reservoir characteristics and unforeseen events (such as hurricanes and other casualties), so we can not predict with any certainty the timing of declines in production or the commencement of production from new projects.
In conjunction with the March 2004 merger, we established a new credit facility maturing on March 2, 2007. The new credit facility was fully drawn at inception for $135 million. In addition, we issued a $10 million promissory note to JEDI as part of the merger consideration. See “- Enron Related Matters” and “- JEDI Term Promissory Note” under Item 1. Net proceeds from a private equity placement were approximately $44 million, of which $6 million was used to pay down the JEDI promissory note with the remainder used to pay down the credit facility. The JEDI note was fully repaid at its maturity date of March 2, 2006.
For the years ended December 31, 2005 and 2004, our interest rate sensitivity for a change in interest rates of 1/8 percent on average outstanding debt under our credit facility is approximately $0.1 million and $0.1 million, respectively. The LIBOR rate on which our bank borrowings are primarily based was 4.69% as of March 2, 2006.
We had a net cash inflow of $2.0 million in 2005 compared to a net cash outflow of $57.6 million in 2004 and a net cash inflow of $41.8 million in 2003. A discussion of the major components of cash flows for these periods follows.
Cash flows provided by operating activities in 2005 increased by $9.9 million compared to 2004. The increase was primarily due to negative changes in working capital offset by lowered operating revenues. Cash flows provided by operating activities in 2004 increased by $66.6 million compared to 2003 primarily due to improved operating results and net income driven by increased production volumes and higher net oil and natural gas prices realized by Mariner.
Cash flows used in investing activities in 2005 increased by $99.5 million compared to 2004 due to increased capital expenditures in 2005. Cash flows used in investing activities in 2004 increased by
$201.2 million compared to 2003 due to increased capital expenditures in 2004 and the sale of assets in prior years.
Cash flows provided by financing activities in 2005 were primarily the result of proceeds from a private equity offering in March 2005 ($44 million) and net borrowings under our revolving credit facility ($47 million). Cash flows used in financing activities in 2004 decreased by $35.1 million compared to 2003 as a result of a $166 million dividend to our former indirect parent used to help repay a term loan to an affiliate of Enron Corp. and the placement of our revolving credit facility.
Commodity Prices and Related Hedging Activities
The energy markets have historically been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. In an effort to reduce the effects of the volatility of the price of oil and natural gas on our operations, management has adopted a policy of hedging oil and natural gas prices from time to time primarily through the use of commodity price swap agreements and costless collar arrangements. While the use of these hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements.
As of December 31, 2005, Mariner had the following hedge contracts outstanding:
As of December 31, 2004, Mariner had the following hedge contracts outstanding:
We have reviewed the financial strength of our hedge counterparties and believe our credit risk to be minimal. Under the terms of some of these transactions, from time to time we may be required to provide security in the form of cash or letters of credit to our counterparties. As of December 31, 2005 and December 31, 2004, we had no deposits for collateral with our counterparties.
The following table sets forth the results of third party hedging transactions during the periods indicated:
In accordance with purchase price accounting implemented at the time of the merger of our former indirect parent on March 2, 2004, we recorded the mark-to-market liability of our hedge contracts at such date totaling $12.4 million as a liability on our balance sheet. See “-Critical Accounting Policies and Estimates-Hedging Program.” For the years ended December 31, 2005 and 2004, $4.5 million and $7.9 million, respectively, of the $53.8 million and $27.7 million total decrease in natural gas and oil sales, respectively, of cash hedge losses relate to the liability recorded at the time of the merger.
Interest Rate Hedges
Borrowings under our revolving credit the facility, discussed below, mature on March 2, 2010, and bear interest at either a LIBOR-based rate or a prime-based rate, at our option, plus a specified margin. Both options expose us to risk of earnings loss due to changes in market rates. We have not entered into interest rate hedges that would mitigate such risk.
Credit Facility
On March 2, 2006, at the closing of the merger with Forest Energy Resources, Mariner and Mariner Energy Resources, Inc. entered into a $500 million senior secured revolving credit facility, and an additional $40 million senior secured letter of credit facility. The revolving credit facility will mature on March 2, 2010, and the $40 million letter of credit facility will mature on March 2, 2009. We used borrowings under the revolving credit facility to facilitate the merger and to retire existing debt, and we may use borrowings in the future for general corporate purposes. The $40 million letter of credit facility has been used to obtain a letter of credit in favor of Forest to secure performance of our obligations under an existing drill-to-earn program.
The outstanding principal balance of loans under the revolving credit facility may not exceed the borrowing base, which has been initially set at $400 million. The borrowing base will be redetermined semi-annually by the lenders. In addition, the agent and Mariner may request one additional redetermination during the interval between each scheduled redetermination, and the agent may request redeterminations in connection with certain property dispositions that equal or exceed 5% of the then current borrowing base, certain gas imbalances that exceed $50 million, and certain bond issuances, which would include Mariner’s proposed high yield debt offering (see “- Cash Flows and Liquidity”). In addition, the borrowing base automatically reduces by an amount equal to 25% of the gross proceeds from such bond issuances. If the borrowing base falls below the outstanding balance under the revolving credit facility, we will be required to prepay the deficit, pledge additional unencumbered collateral, repay the deficit and cash collateralize certain letters of credit, or some combination of such prepayment, pledge, and repayment and collateralization.
Interest under the revolving credit facility is determined by reference to the following grid:
Applicable Margin
Interest is payable quarterly for Union Bank of California Reference Rate loans and at the applicable maturity date for LIBOR (London interbank offered rate) loans. The fee for letters of credit issued under the revolving credit facility is the LIBOR margin indicated in the grid, per annum. The fee for letters of credit under the letter of credit facility is 1.50% due quarterly in advance.
The obligations under the credit facilities are secured by first priority liens on substantially all of our real and personal property, including our existing and after-acquired oil and gas properties and related real property interests. Additionally, the obligations under the credit facilities are guaranteed by us and each of our subsidiaries.
The credit facilities contain various covenants that limit our ability to do the following, among other things:
•
incur certain indebtedness;
•
grant certain liens;
•
merge or consolidate with another entity;
•
sell property or other assets which generate proceeds in excess of 5% of the then current borrowing base;
•
make certain loans or investments, or dividends or other payments in respect of equity or bonds; and
•
enter new lines of business.
The credit facilities also contain covenants, which, among other things, require us to maintain specified ratios as follows:
•
consolidated current assets plus the unused borrowing base to consolidated current liabilities of not less than 1.0 to 1.0; and
•
total debt to consolidated EBITDA of not more than 2.5 to 1.0.
If an event of default exists under the credit facilities, the lenders will be able to accelerate the maturity of the credit facilities and exercise other rights and remedies. Events of default include defaults in payment or performance under the credit facilities, misrepresentations, cross-defaults to other debt or material obligations, and insolvency, material adverse judgments, change of control (including certain changes in ownership and in the event Mr. Scott D. Josey ceases to be involved in Mariner’s management, the failure to timely replace him with someone with comparable qualifications) and any material adverse change.
As of March 2, 2006, $350 million was utilized under the credit facility, and the weighted average interest rate was 7.75%.
JEDI Term Promissory Note
As part of the 2004 merger consideration payable to JEDI, we issued a term promissory note to JEDI in the amount of $10 million. The note bore interest, payable in kind at our option, at a rate of 10% per annum until March 2, 2005, and 12% per annum thereafter unless paid in cash in which event the rate remained 10% per annum. We chose to pay the interest in cash rather than in kind. The JEDI note was secured by a lien on three of our properties with no proved reserves located in the Gulf of Mexico. We could offset against the note the amount of certain claims for indemnification that could be asserted against JEDI under the terms of the merger agreement. The JEDI term promissory note contained customary events of default, including an event of default triggered by the occurrence of an event of default under our credit facility. We used $6 million of the proceeds from the 2005 private equity placement to repay a portion of the JEDI note. As of December 31, 2005, $4 million was still outstanding under the JEDI note. This note was repaid in full on its maturity date of March 2, 2006.
Capital Expenditures and Capital Resources
The following table presents major components of our capital expenditures for each of the three years in the period ended December 31, 2005.
Our net capital expenditures for 2005 increased by $103.8 million as compared to 2004, primarily as a result of increased acquisitions, primarily in West Texas, and increased expenditures on development activities. Our net capital expenditures for 2004 increased by $187.2 million, as compared to 2003, as a result of increased exploration and development expenditures with no offsetting proceeds from property conveyances in 2004.
We had no long-term debt outstanding as of December 31, 2003. As of December 31, 2005 and 2004, long-term debt was $156 million and $115 million, respectively. See “-Credit Facility.”
Contractual Commitments
We have numerous contractual commitments in the ordinary course of business, debt service requirements and operating lease commitments. The following table summarizes these commitments at December 31, 2005:
(1)
As of December 31, 2005, we had incurred debt obligations under our credit facility and the JEDI promissory note that are due as follows: $4 million in 2006; and $152 million in 2007. On March 2, 2006, we incurred an additional $176.2 million of debt in connection with the Forest Energy Resources merger. Our total debt as of March 2, 2006 was approximately $346 million under our amended and restated credit facility that extended the maturity date to March 2, 2010.
(2)
Interest obligations represent approximately 12 months of interest due on the JEDI promissory note at 10%. Future interest obligations under our credit facility are uncertain, due to the variable interest rate on fluctuating balances. Based on a 7.15% weighted average interest rate on amounts outstanding under our credit facility as of December 31, 2005, $10.9 million and $1.8 million would be due under the credit facility in 2006 and 2007, respectively. Based on a 7.75% weighted average interest rate on amounts outstanding under our amended and restated credit facility as of March 2, 2006, $22.8 million, $81.7 million and $4.5 million would be due under the credit facility in less than one year, 1-3 years and 3-5 years, respectively.
MMS Appeal-Mariner operates numerous properties in the Gulf of Mexico. Two of such properties were leased from the MMS subject to the RRA. The RRA relieved the obligation to pay royalties on certain predetermined leases until a designated volume is produced. These two leases contained language that limited royalty relief if commodity prices exceeded predetermined levels. For the years 2000, 2001, 2003 and 2004, commodity prices exceeded the predetermined levels. Management believes the MMS did not have the authority to set pricing limits, and Mariner filed an administrative appeal with the MMS and has withheld royalties regarding this matter. The MMS filed a motion to dismiss our appeal with the Department of the Interior’s Board of Land Appeals. On April 6, 2005, the Board of Land Appeals granted the MMS’ motion and dismissed our appeal. On October 3, 2005, we filed suit in the U.S. District Court for the Southern District of Texas seeking judicial review of the dismissal of our appeal by the Board of Land Appeals. Mariner has recorded a liability for 100% of the exposure on this matter which on December 31, 2005 was $16.0 million. For additional information concerning the contested royalty payments and the MMS’s demands, see “-Legal Proceedings” under Item 3.
Off-Balance Sheet Arrangements
Transportation Contract-In 1999, Mariner constructed a 29-mile flowline from a third party platform to the Mississippi Canyon 674 subsea well. After commissioning, MEGS LLC, an Enron affiliate, purchased the flowline from Mariner and its joint interest partner. In addition, Mariner entered into a firm transportation contract with MEGS LLC at a rate of $0.26 per MMBtu to transport Mariner’s share of approximately 130,000,000 MMbtus of natural gas from the commencement of production through March 2009. Mariner’s working interest in the well is 51%. For the year ended December 31, 2003, Mariner paid $1.9 million on this contract. The remaining volume commitment was 14,707,107 MMbtus or $3.8 million net to Mariner. Pursuant
to the contract, Mariner was required to deliver minimum quantities through the flowline or be subject to minimum monthly payment requirements.
On May 10, 2004, Mariner and the other 49% working interest owner in the Mississippi Canyon 674 well purchased the flowline from MEGS LLC for an adjusted purchase price of approximately $3.8 million, of which approximately $1.9 million was paid by Mariner, and terminated the transportation contract and associated liability. Accordingly, we currently have no off-balance sheet arrangements.
On March 2, 2006, Mariner obtained a $40 million letter of credit under its senior secured letter of credit facility. The letter of credit was issued in favor of Forest to secure our performance of our obligations under an existing drill-to-earn program.
Recent Accounting Pronouncements
Recent Accounting Pronouncements-In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 153, “Exchanges of Nonmonetary Assets, an Amendment of APB Opinion No. 29,” which provides that all nonmonetary asset exchanges that have commercial substance must be measured based on the fair value of the assets exchanged and any resulting gain or loss recorded. An exchange is defined as having commercial substance if it results in a significant change in expected future cash flows. Exchanges of operating interests by oil and gas producing companies to form a joint venture continue to be exempted. APB Opinion No. 29 previously exempted all exchanges of similar productive assets from fair value accounting, therefore resulting in no gain or loss recorded for such exchanges. SFAS No. 153 became effective for fiscal periods beginning on or after June 15, 2005. Accordingly, we adopted this statement effective June 30, 2005, and it did not have a material impact on our consolidated financial position, results of operations or cash flows.
In March 2005, the FASB issued Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations,” which clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when the obligation is incurred - generally upon acquisition, construction, or development and/or through the normal operation of the asset, if the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Uncertainty about the timing and/or method of settlement is required to be factored into the measurement of the liability when sufficient information exists. We adopted FIN No. 47 on December 31, 2005 and it did not have a material impact on our consolidated financial position, results of operations or cash flows.
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3.” SFAS No. 154 changes the requirements for the accounting and reporting of a change in accounting principle, including voluntary changes in accounting principle and changes required by an accounting pronouncement that does not include specific transition provisions. SFAS No. 154 requires retrospective application to prior period financial statements of changes in accounting principle. If impractical to determine either the period-specific effects or the cumulative effect of the change, the new accounting principle would be applied as if it were adopted prospectively from the earliest date practical. The correction of errors in prior period financial statements should be identified as a “restatement.” SFAS No. 154 is effective for fiscal years beginning after December 15, 2005. Accordingly, we adopted this statement effective January 1, 2006 and, upon adoption, it did not have a material impact on our consolidated financial position, results of operations or cash flows.
In September 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF Issue 04-13 requires that purchases and sales of inventory with the same counterparty in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. The consensus is effective for inventory arrangements entered into, modified or renewed in interim or annual reporting periods beginning after March 15, 2006. We do not expect the adoption of this EITF Issue to have a material impact on our consolidated financial position, results of operations or cash flows.
In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments - an amendment of FASB Statements No. 133 and 140.” SFAS No. 155 simplifies the accounting for certain hybrid financial instruments, eliminates the FASB’s interim guidance which provides that beneficial interests in securitized financial assets are not subject to the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and eliminates the restriction on the passive derivative instruments that a qualifying special-purpose entity may hold. 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 do not expect this Statement to have a material impact on our consolidated financial position, results of operations or cash flows.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
For a discussion of our market risk, See “- Liquidity and Capital Resources - Commodity Prices and Related Hedging Activities” and “- Liquidity and Capital Resources - Interest Rate Hedges” in Item 7.
Item 8.
Item 8.
Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors & Stockholders
Mariner Energy, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Mariner Energy, Inc. (the “Company”) as of December 31, 2005 and 2004 and the related consolidated statements of operations, stockholders’ equity and comprehensive income and cash flows for the year ended December 31, 2005, for the period January 1, 2004 through March 2, 2004 (Pre-merger), for the period from March 3, 2004 through December 31, 2004 (Post merger), and for the year ended December 31, 2003 (Pre-merger). 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 Mariner Energy, Inc. as of December 31, 2005 and 2004, and the results of its operations and cash flows for the year ended December 31, 2005, for the period January 1, 2004 through March 2, 2004 (Pre-merger), for the period from March 3, 2004 through December 31, 2004 (Post merger), and for the year ended December 31, 2003 (Pre-merger) in conformity with accounting principles generally accepted in the United States of America.
The Company changed its method of accounting for asset retirement obligations in 2003. This change is discussed in Note 1 to the Consolidated Financial Statements.
As described in Note 1 to the Consolidated Financial Statements, on March 2, 2004, Mariner Energy LLC, the Company’s parent company, merged with an affiliate of the private equity funds Carlyle/Riverstone Global Energy and Power Fund II, L.P. and ACON Investments LLC.
DELOITTE & TOUCHE LLP
Houston, Texas
March 30, 2006
MARINER ENERGY, INC.
BALANCE SHEETS
The accompanying notes are an integral part of these financial statements
MARINER ENERGY, INC.
STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these financial statements
MARINER ENERGY, INC.
STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
The accompanying notes are an integral part of these financial statements
MARINER ENERGY, INC.
STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these financial statements
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
1.
Summary of Significant Accounting Policies
Operations-Mariner Energy, Inc. (the “Company”) is an independent oil and gas exploration, development and production company with principal operations in the Gulf of Mexico, both shelf and deepwater, and the Permian Basin in West Texas.
Organization-On March 2, 2004, Mariner Energy LLC, the parent company of Mariner Energy, Inc. (the “Company”), merged with a subsidiary of MEI Acquisitions Holdings, LLC, an affiliate of the private equity funds Carlyle/Riverstone Global Energy and Power Fund II, L.P. and ACON Investments LLC (the “Merger”). Prior to the Merger, Joint Energy Development Investments Limited Partnership (“JEDI”), which is an indirect wholly-owned subsidiary of Enron Corp. (“Enron”), owned approximately 96% of the common stock of Mariner Energy LLC (see Note 2). In the Merger, all the shares of common stock in Mariner Energy LLC were converted into the right to receive cash and certain other consideration. As a result, JEDI no longer owns any interest in Mariner Energy LLC, and the Company is no longer affiliated with JEDI or Enron.
Simultaneously with the Merger, the Company obtained a revolving line of credit with initial advances of $135 million from a group of banks. The loan proceeds and an additional $31.2 million of Company funds distributed to Mariner Energy LLC were used to pay a portion of the gross Merger consideration (which included repayment of $197.6 million of Mariner Energy LLC debt outstanding at the time of the Merger) and estimated transaction costs and expenses associated with the Merger and bank financing. The Company also issued a $10 million note and assigned a fully reserved receivable valued at $1.9 million to JEDI as part of JEDI’s Merger consideration. In addition, pursuant to the Merger agreement, JEDI agreed to indemnify the Company from certain liabilities and the Company agreed to pay additional Merger consideration contingent upon the outcome of a certain five well drilling program that was completed in the second quarter of 2004. In September 2004, the Company paid approximately $161,000 as additional Merger consideration related to the five well drilling program, and the Company believes it has fully discharged its obligations thereunder.
The sources and uses of funds related to the Merger were as follows:
As a result of the change in control, accounting principles generally accepted in the United States requires the Merger and the resulting acquisition of Mariner Energy LLC by MEI Acquisitions Holdings, LLC to be accounted for as a purchase transaction in accordance with Statement of Financial Accounting Standards No. 141, “Business Combinations”. Staff Accounting bulletin No. 54 (“SAB 54”) requires the application of “push down accounting” in situations where the ownership of an entity has changed, meaning that the post-transaction financial statements of the Company reflect the new basis of accounting. Accordingly, the financial
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
statements as of December 31, 2004 reflect the Company’s fair value basis resulting from the acquisition that has been pushed down to the Company. The aggregate purchase price has been allocated to the underlying assets and liabilities based upon the respective estimated fair values at March 2, 2004 (date of Merger). The allocation of the purchase price has been finalized. Carryover basis accounting applies for tax purposes. Based on subsequent tax filings during the year ended December 31, 2005, the Company recorded a $4.3 million adjustment to the estimated tax basis at acquisition. All financial information presented prior to March 2, 2004 represents the basis of accounting used by the pre-Merger entity. The period January 1, 2004 through March 2, 2004 is referred to as 2004 Pre-Merger and the period March 3, 2004 through December 31, 2004 is referred to as 2004 Post-Merger.
The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the March 2, 2004 acquisition:
ALLOCATION OF PURCHASE PRICE TO MARINER ENERGY, INC.
(1)
Represents deferred income taxes recorded at the date of the Merger due to differences between the book basis and the tax basis of assets. For book purposes, we had a step-up in basis related to purchase accounting while our existing tax basis carried over.
The following reflects the unaudited pro forma results of operations as though the Merger had been consummated at January 1, 2004.
On February 10, 2005, in anticipation of the Company’s private placement of 31,452,500 shares of common stock (the “Private Equity Offering”), Mariner Holdings, Inc. (the direct parent of Mariner Energy, Inc.) and Mariner Energy LLC (the direct parent of Mariner Holdings, Inc.) were merged into Mariner Energy,
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
Inc. and ceased to exist. The mergers of Mariner Holdings, Inc. and Mariner Energy LLC into the Company had no operational or financial impact on the Company; however, intercompany receivables of $0.2 million and $2.9 million in cash held by the affiliates were transferred to the Company in February 2005 and accounted for as additional paid-in capital.
On March 2, 2006, the Company completed a merger transaction with Forest Energy Resources, Inc. As a result of this merger, the Company acquired the offshore Gulf of Mexico operations of Forest Oil Corporation and amended and restated its credit facility. See Note 9, “Subsequent Events.”
Net Income Per Share-Basic earnings per share is calculated by dividing net income by the weighted average number of shares of common stock outstanding during the period. Fully diluted earnings per share assumes the conversion of all potentially dilutive securities and is calculated by dividing net income by the sum of the weighted average number of shares of common stock outstanding plus all potentially dilutive securities.
Effective March 3, 2005, we effected a stock split increasing our authorized shares from 2,000,000 to 70,000,000 and our outstanding shares from 1,380 to 29,748,130. We also changed the stated par value of our stock from $1 to $.0001 per share. The accompanying financial and earnings per share information has been restated utilizing the post-split shares. Effective with our merger on March 2, 2004, all company stock option plans and associated outstanding stock options were canceled.
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
For the periods presented prior to 2005, Mariner Energy, Inc. had no outstanding stock options so the basic and diluted earnings per share were the same. In March 2005, 2,267,270 restricted stock awards were granted under the Equity Participation Plan and 787,360 stock options were granted under the Stock Incentive Plan. During the second and third quarters of 2005, an additional 21,640 stock options were granted under the Stock Incentive Plan for a total of 809,000 stock options outstanding as of December 31, 2005. Outstanding restricted stock and unexercised stock options diluted earnings by $0.04 per share for the year ended December 31, 2005.
Cash and Cash Equivalents-All short-term, highly liquid investments that have an original maturity date of three months or less are considered cash equivalents.
Receivables-Substantially all of the Company’s receivables arise from sales of oil or natural gas, or from reimbursable expenses billed to the other participants in oil and gas wells for which the Company serves as operator. We routinely assess the recoverability of all material trade and other receivables to determine their collectibility. We accrue a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated.
Oil and Gas Properties-Oil and gas properties are accounted for using the full-cost method of accounting. All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and gas properties are capitalized. Amortization of oil and gas properties is provided using the unit-of-production method based on estimated proved oil and gas reserves. No gains or losses are recognized upon the sale or disposition of oil and gas properties unless the sale or disposition represents a significant quantity of oil and gas reserves, which would have a significant impact on the depreciation, depletion and amortization rate.
Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of future net revenues, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. If capitalized costs (net of accumulated depreciation, depletion and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date.
The ceiling test is calculated using natural gas and oil prices in effect as of the balance sheet date and adjusted for “basis” or location differential, held constant over the life of the reserves. We use derivative financial instruments that qualify for cash flow hedge accounting under SFAS 133 to hedge against the volatility of natural gas prices and, in accordance with SEC guidelines, we include estimated future cash flows from our hedging program in our ceiling test calculation. In addition, subsequent to the adoption of SFAS 143, “Accounting for Asset Retirement Obligations,” the future cash outflows associated with settling asset retirement obligations are not included in the computation of the discounted present value of future net revenues for the purposes of the ceiling test calculation.
Unproved Properties-The costs associated with unevaluated properties and properties under development are not initially included in the full cost amortization base and relate to unproved leasehold acreage, seismic data, wells and production facilities in progress and wells pending determination together with interest costs
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
capitalized for these projects. Unevaluated leasehold costs are transferred to the amortization base once determination has been made or upon expiration of a lease. Geological and geophysical costs, including 3-D seismic data costs, are included in the full cost amortization base as incurred when such costs cannot be associated with specific unevaluated properties for which we own a direct interest. Seismic data costs are associated with specific unevaluated properties if the seismic data is acquired for the purpose of evaluating acreage or trends covered by a leasehold interest owned by us. We make this determination based on an analysis of leasehold and seismic maps and discussions with our Chief Exploration Officer. Geological and geophysical costs included in unproved properties are transferred to the full cost amortization base along with the associated leasehold costs on a specific project basis. Costs associated with wells in progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. All items included in our unevaluated property balance are assessed on a quarterly basis for possible impairment or reduction in value.
Other Property and Equipment-Depreciation of other property and equipment is provided on a straight-line basis over their estimated useful lives, which range from three to twenty-two years.
Prepaid Expenses and Other-Prepaid expenses and other includes $3.3 million of oil and gas lease and well equipment held in inventory at December 31, 2005. In 2005 and 2004, we reduced the carrying cost of our inventory by $1.8 million and $1.0 million, respectively, to account for a reduction in the estimated value, primarily related to subsea trees and wellhead equipment held in inventory. Other current assets at December 31, 2005 also include prepaid insurance and seismic costs of $13.9 million and deferred offering costs of $3.8 million related to the merger with Forest Energy Resources.
Other Assets-Other assets as of December 31, 2005 were primarily comprised of $1.4 million of amortizable bank fees, $2.3 million in non-current receivables and $4.3 million of prepaid seismic costs. Other assets as of December 31, 2004 were primarily comprised of $2.5 million of amortizable bank fees and various deposits held by third parties. Accumulated amortization as of December 31, 2005 and 2004 was $2.1 million and $0.9 million, respectively.
Production Costs-All costs relating to production activities, including workover costs incurred to maintain production, are charged to expense as incurred.
General and Administrative Costs and Expenses-Under the full cost method of accounting, a portion of our general and administrative expenses that are attributable to our acquisition, exploration and development activities are capitalized as part of our full cost pool. These capitalized costs include salaries, employee benefits, costs of consulting services and other costs directly identified with acquisition exploration and development activities. We capitalized general and administrative costs related to our acquisition, exploration and development activities, during 2005, 2004 and 2003 of $5.3 million, $6.9 million and $6.6 million, respectively.
We receive reimbursement for administrative and overhead expenses incurred on behalf of other working interest owners on properties we operate. These reimbursements totaling $6.9 million, $4.4 million and $1.8 million for the years ended December 31, 2005, 2004 and 2003, respectively, were allocated as reductions to general and administrative expenses incurred. Generally, we do not receive any reimbursements or fees in excess of the costs incurred; however, if we did, we would credit the excess to the full cost pool to be recognized through lower cost amortization as production occurs.
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
Income Taxes-The Company’s taxable income is included in a consolidated United States income tax return with Mariner Energy LLC. In February 2005, Mariner Energy LLC was merged into Mariner Energy, Inc. Following the effective date of that merger through March 2006, Mariner Energy, Inc. will file its own income tax return. After the Forest merger in March 2006 merger, the Company’s taxable income will be included in a consolidated United States income tax return with Forest Energy Resources and the Company’s other subsidiaries. The intercompany tax allocation policy provides that each member of the consolidated group compute a provision for income taxes on a separate return basis. The Company records its income taxes using an asset and liability approach which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax bases of assets and liabilities. Valuation allowances are established when necessary to reduce deferred tax assets to the amount more likely than not to be recovered.
Capitalized Interest Costs-The Company capitalizes interest based on the cost of major development projects which are excluded from current depreciation, depletion, and amortization calculations. Capitalized interest costs were approximately $0.7 million for 2005, $0.4 and $-0- million for 2004 Post-merger and 2004 Pre-merger, respectively, and $0.7 million for 2003.
Accrual for Future Abandonment Costs-Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations,” addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 was adopted on January 1, 2003. SFAS No. 143 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record (i) an $11.3 million increase in the carrying values of proved properties, and (ii) a $4.5 million increase in current abandonment liabilities. The net impact of these items was to record a pre-tax gain of $3.0 million as a cumulative effect adjustment of a change in accounting principle in the Company’s statements of operations upon adoption on January 1, 2003.
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The following roll forward is provided as a reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligation.
(1)
Includes $4.7 million classified as a current accrued liability at December 31, 2004.
(2)
Includes $11.4 million classified as a current accrued liability at December 31, 2005.
Hedging Program-The Company utilizes derivative instruments in the form of natural gas and crude oil price swap agreements and costless collar arrangements in order to manage price risk associated with future crude oil and natural gas production and fixed-price crude oil and natural gas purchase and sale commitments. Such agreements are accounted for as hedges using the deferral method of accounting. Gains and losses resulting from these transactions, recorded at market value, are deferred and recorded in Accumulated Other Comprehensive Income (“AOCI”) as appropriate, until recognized as operating income in the Company’s Statement of Operations as the physical production hedged by the contracts is delivered.
The net cash flows related to any recognized gains or losses associated with these hedges are reported as oil and gas revenues and presented in cash flows from operations. If the hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period as the physical production hedged by the contracts is delivered.
The conditions to be met for a derivative instrument to qualify as a cash flow hedge are the following: (i) the item to be hedged exposes the Company to price risk; (ii) the derivative reduces the risk exposure and is designated as a hedge at the time the derivative contract is entered into; and (iii) at the inception of the hedge and throughout the hedge period there is a high correlation of changes in the market value of the derivative instrument and the fair value of the underlying item being hedged.
When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on sale or settlement of the underlying item. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if correlation no longer exists, the gain or loss on the derivative is recognized in income
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
to the extent the future results have not been offset by the effects of price or interest rate changes on the hedged item since the inception of the hedge.
Revenue Recognition-We use the entitlements method of accounting for the recognition of natural gas and oil revenues. Under this method of accounting, income is recorded based on our net revenue interest in production or nominated deliveries. We incur production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over-and-under deliveries or by cash settlement, as required by applicable contracts. Production imbalances are marked-to-market at the end of each month at the lowest of (i) the price in effect at the time of production; (ii) the current market price; or (iii) the contract price, if a contract is in hand.
The Company’s gas balancing assets and liabilities are not material as oil and gas volumes sold are not significantly different from the Company’s share of production.
Financial Instruments-The Company’s financial instruments consist of cash and cash equivalents, receivables, payables and outstanding debt. The carrying amount of the Company’s other instruments noted above approximate fair value due to the short-term nature of these investments. The carrying amount of our long-term debt approximates fair value as the interest rates are generally indexed to current market rates.
Use of Estimates in the Preparation of Financial Statements-The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from these estimates.
Major Customers-During the twelve months ended December 31, 2005, sales of oil and gas to three purchasers accounted for 24%, 10% and 15% of total revenues. During the year ended December 31, 2004, sales of oil and gas to three purchasers, including an Enron affiliate, accounted for 27%, 18% and 12% of total revenues. During the year ended December 31, 2003, sales of oil and gas to three purchasers, including an Enron affiliate, accounted for 34%, 19% and 14% of total revenues. Management believes that the loss of any of these purchasers would not have a material impact on the Company’s financial condition, results of operations or cash flows.
Stock Options-The Company (as allowed by SFAS No. 123 “Accounting for Stock Based Compensation” as amended by SFAS No. 148 “Accounting for Stock-Based Compensation-Transition and Disclosure”) has historically applied APB Opinion No. 25 “Accounting for Stock Issued to Employees” for its grants made pursuant to its employee stock option plans. The Company applies APB Opinion 25 and related interpretations in accounting for the Stock Option Plan. Accordingly, no compensation cost has been recognized for the Stock Option Plan. Had compensation cost for the Stock Option Plan been determined based on the fair value at the grant date for awards under the Stock Option Plan consistent with the method of SFAS No. 123, the Company’s net income for the years ended December 31, 2004 and 2003 would not have changed.
Effective January 1, 2005, we adopted the fair value expense recognition provisions of SFAS 123(R). Using the modified retrospective application, the Company would be required to give effect to the fair-value based method of accounting for awards granted, modified, or settled in cash in fiscal years beginning after December 15, 1994 on a basis consistent with the pro forma disclosures required for those periods by Statement 123, as amended by FASB Statement No. 14 “Accounting for Stock Based
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
Compensation-Transition and Disclosure”. Since the Company had no employee stock options plans in effect at January 1, 2005, adoption of this method is expected to have no impact on historical information presented by the Company.
As a result of the adoption of the above described SFAS No. 123(R), we recorded compensation expense for the fair value of restricted stock that was granted pursuant to our Equity Participation Plan (see “Management of Mariner-Equity Participation Plan”) and for subsequent grants of stock options or restricted stock made pursuant to the Mariner Energy, Inc. Stock Incentive Plan (see “Management of Mariner-Stock Incentive Plan”). We recorded compensation expense for the restricted stock grants equal to their fair value at the time of the grant, amortized pro rata over the restricted period. General and administrative expense for the year ended December 31, 2005 includes $25.7 million of compensation expense related to restricted stock granted in 2005 and $0.6 million of compensation expense related to stock options outstanding as of December 31, 2005. For the year ended December 31, 2004, we recorded no stock compensation expense related to either restricted stock or stock options.
Recent Accounting Pronouncements-In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 153, “Exchanges of Nonmonetary Assets, an Amendment of APB Opinion No. 29,” which provides that all nonmonetary asset exchanges that have commercial substance must be measured based on the fair value of the assets exchanged and any resulting gain or loss recorded. An exchange is defined as having commercial substance if it results in a significant change in expected future cash flows. Exchanges of operating interests by oil and gas producing companies to form a joint venture continue to be exempted. APB Opinion No. 29 previously exempted all exchanges of similar productive assets from fair value accounting, therefore resulting in no gain or loss recorded for such exchanges. SFAS No. 153 became effective for fiscal periods beginning on or after June 15, 2005. Accordingly, we adopted this statement effective June 30, 2005, and it did not have a material impact on our consolidated financial position, results of operations or cash flows.
In March 2005, the FASB issued Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations,” which clarifies that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when the obligation is incurred - generally upon acquisition, construction, or development and/or through the normal operation of the asset, if the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Uncertainty about the timing and/or method of settlement is required to be factored into the measurement of the liability when sufficient information exists. We adopted FIN No. 47 on December 31, 2005 and it did not have a material impact on our consolidated financial position, results of operations or cash flows.
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3.” SFAS No. 154 changes the requirements for the accounting and reporting of a change in accounting principle, including voluntary changes in accounting principle and changes required by an accounting pronouncement that does not include specific transition provisions. SFAS No. 154 requires retrospective application to prior period financial statements of changes in accounting principle. If impractical to determine either the period-specific effects or the cumulative effect of the change, the new accounting principle would be applied as if it were adopted prospectively from the earliest date practical. The correction of errors in prior period financial statements should be identified as a “restatement.” SFAS No. 154 is effective for fiscal years beginning after December 15, 2005. Accordingly, we
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
adopted this statement effective January 1, 2006 and, upon adoption, it did not have a material impact on our consolidated financial position, results of operations or cash flows.
In September 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF Issue 04-13 requires that purchases and sales of inventory with the same counterparty in the same line of business should be accounted for as a single non-monetary exchange, if entered into in contemplation of one another. The consensus is effective for inventory arrangements entered into, modified or renewed in interim or annual reporting periods beginning after March 15, 2006. We do not expect the adoption of this EITF Issue to have a material impact on our consolidated financial position, results of operations or cash flows.
In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments - an amendment of FASB Statements No. 133 and 140.” SFAS No. 155 simplifies the accounting for certain hybrid financial instruments, eliminates the FASB’s interim guidance which provides that beneficial interests in securitized financial assets are not subject to the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and eliminates the restriction on the passive derivative instruments that a qualifying special-purpose entity may hold. 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 do not expect this Statement to have a material impact on our consolidated financial position, results of operations or cash flows.
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
2.
Related Party Transactions
Organization and Ownership of the Company-Until February 10, 2005, the Company was a wholly-owned subsidiary of Mariner Holdings, Inc., which was a wholly-owned subsidiary of Mariner Energy LLC. From April 1, 1996, until October 1998, Mariner Holdings, Inc. was a majority-owned subsidiary of JEDI, an affiliate of Enron. In October 1998, JEDI and other stockholders of Mariner Holdings, Inc. exchanged all of their common shares of Mariner Holdings, Inc. for an equivalent ownership percentage in Mariner Energy LLC. From October 1998 until the Merger, Mariner Energy LLC was a majority-owned subsidiary of JEDI.
During the period of JEDI’s ownership of the Company, Mariner Energy LLC and the Company entered into various financing and operating transactions, such as oil and gas sale transactions, commodity price hedge transactions, and financial transactions with affiliates of Enron. Below is a summary of key transactions between the Company or Mariner Energy LLC and Enron-affiliated entities.
On February 10, 2005, in anticipation of the Private Equity Offering, Mariner Holdings, Inc. (the direct parent of Mariner Energy, Inc.) and Mariner Energy LLC (the direct parent of Mariner Holdings, Inc.) were merged into Mariner Energy, Inc. and ceased to exist. The mergers of Mariner Holdings, Inc. and Mariner Energy LLC into the Company had no operational or financial impact on the Company.
Mariner Energy LLC
Enron Affiliate Term Loan-In March 2000, Mariner Energy LLC established an unsecured term loan with Enron North America Corp. (“ENA”), an affiliate of Enron, to repay amounts outstanding under various affiliate credit facilities at Mariner Energy LLC and the Company and provide additional working capital. The loan bore interest at 15%, which interest accrued and was added to the loan principal. In conjunction with the loan, warrants were issued to ENA providing the right to purchase up to 900,000 common shares of Mariner Energy LLC for $0.01 per share. The loan and warrants were subsequently assigned by ENA to another Enron affiliate. In connection with the Merger, the loan balance, which was approximately $192.8 million as of December 31, 2003, was repaid in full, and the warrants were exercised and the holders received their pro rata portion of the Merger consideration.
Mariner Energy, Inc.
As of March 2, 2004 the Company is no longer affiliated with Enron.
Oil and Gas Production Sales to Enron Affiliates-During the years ending December 31, 2004 and 2003, sales of oil and gas production to Enron affiliates were $62.6 million and $32.6 million, respectively. These sales were generally made on one to three month contracts. At the time Enron filed its petition for bankruptcy protection in December 2001, the Company immediately ceased selling its physical production to Enron Upstream Company, LLC, an Enron affiliate; however, it continued to sell its production to Bridgeline Gas Marketing, LLC, another Enron affiliate. No default in payment by Bridgeline has occurred. As of December 31, 2001, after Enron filed for bankruptcy protection, the Company had an outstanding receivable of $3.0 million from ENA Upstream related to sales of production. This amount was not paid as scheduled. In 2001, we fully allowed for its uncollectability and reduced the outstanding receivable to $-0-. The Company submitted a proof of claim to the bankruptcy court presiding over the Enron bankruptcy for amounts owed to it by ENA Upstream. As part of the Merger consideration, the Company assigned this and another receivable to JEDI at an agreed value of approximately $1.9 million.
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
Price Risk Management Activities-The Company engages in price risk management activities from time to time. These activities are intended to manage its exposure to fluctuations in commodity prices for natural gas and crude oil. The Company primarily utilizes price swaps as a means to manage such risk. Prior to the Enron bankruptcy, all of the Company’s hedging contracts were with ENA. As a result of ENA’s bankruptcy, the November 2001 through April 30, 2002 settlements for oil and gas were not paid when due. On May 14, 2002, the Company elected under its ISDA Master Agreement with ENA to terminate all open hedge contracts. The effect of this termination was to fix the nominal value on all remaining contracts on May 14, 2002. Subsequent to this termination, the value of all oil and natural gas unpaid hedge contracts was $7.7 million. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 137 and No. 138, the Company de-designated its contracts effective December 2, 2001 and recognized all market value changes subsequent to such de-designation in its earnings. The value recorded up to the time of de-designation and included in Accumulated Other Comprehensive Income (“AOCI”) was reclassified out of AOCI and into earnings as the original corresponding production, as hedged by the contracts was produced. As of December 31, 2003, approximately $25.8 million was reclassified to earnings.
As of March 2, 2004 the Company is no longer affiliated with ENA. The following table sets forth the results of hedging transactions during the periods indicated that were made with ENA (all amounts shown are non-cash items):
Supplemental ENA Affiliate Data-provided below is supplemental balance sheet and income statement information for affiliate entities reflecting net balances, net of any allowances:
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
Post-Merger Related Party Transactions
In connection with the Merger, Mariner Energy LLC entered into management agreements with two affiliates of MEI Acquisitions Holdings, LLC, the Company’s post-Merger parent company. These agreements provided for the payment by Mariner Energy LLC of an aggregate of $2.5 million to the affiliates in connection with the provision of management services. Such payments have been made. Mariner Energy LLC also entered into monitoring agreements with two affiliates of MEI Acquisitions Holdings, LLC, providing for the payment by Mariner Energy LLC of an aggregate of one percent of its annual EBITDA to the affiliates in connection with certain monitoring activities. Under the terms of the monitoring agreements, the affiliates provided financial advisory services in connection with the ongoing operations of Mariner subsequent to the Merger.
Effective February 7, 2005, these contracts were terminated in consideration of lump sum cash payments by Mariner totalling $2.3 million. The Company recorded the termination payments as general and administrative expenses for the year ended December 31, 2005.
3.
Property Conveyances
In March 2003, the Company sold its remaining 25% working interest in its Falcon and Harrier discoveries and surrounding blocks, located in East Breaks area in the western Gulf of Mexico, for $121.6 million. The Company retained a 41/4 percent overriding royalty interest on seven non-producing blocks. The proceeds from the sale were used for debt reduction, capital expenditures, and other corporate purposes. At March 31, 2003, the Falcon and Harrier projects had approximately 44 Bcfe assigned as proven oil and gas reserves to the Company’s interest. No gain or loss was recognized as a result of this sale, as the sale did not significantly affect the Company’s depletion rate.
4.
Long-Term Debt
Bank Credit Facility-On March 2, 2004, simultaneously with the closing of the Merger, the Company obtained a revolving line of credit with initial advances of $135 million from a group of seven banks (since reduced to six banks) led by Union Bank of California, N.A. and BNP Paribas. Proceeds of these advances were used to pay a portion of the Merger consideration (which included repayment of the debt of Mariner Energy LLC) and transaction costs and expenses associated with the Merger. The bank credit facility provides up to $150 million of revolving borrowing capacity, subject to a borrowing base, and a $25 million term loan. The initial advance was made in two tranches: a $110 million Tranche A and a $25 million Tranche B.
The Tranche A revolving note matures on March 2, 2007. The borrowing capacity under the Tranche A note is subject to a borrowing base initially set at $110 million. The borrowing base initially is subject to
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
redetermination by the lenders quarterly. After the Tranche B note is repaid, provided that at least $10 million of unused availability exists under Tranche A, the borrowing base will be redetermined semi-annually. The borrowing base is based upon the evaluation by the lenders of the Company’s oil and gas reserves and other factors. Any increase in the borrowing base requires the consent of all lenders. On August 5, 2005, the lenders agreed to increase the borrowing base to $170 million. On January 20, 2006, the lenders agreed to increase the borrowing base to $185 million.
Borrowings under the Tranche A note bear interest, at the option of the Company, at a rate of (i) LIBOR plus 2.00% to 2.75% depending upon utilization, or (ii) the greater of (a) the Federal Funds Rate plus 0.50% or (b) the Reference Rate (prime rate), plus 0.00% to 0.50% depending upon utilization.
Borrowings under the Tranche B note bear interest at a rate equal to the greater of (a) the Federal Funds Rate plus 0.50% or (b) the Reference Rate, plus 3.00%. In July 2004 (prior to its December 2, 2004 maturity date) the outstanding Tranche B note was converted to a Tranche A note, and all subsequent advances under the credit facility are Tranche A advances. Once repaid, the Tranche B advances may not be reborrowed.
Substantially all of the Company’s assets, other than the assets securing the term Promissory Note issued to JEDI, are pledged to secure the bank credit facility. The Company must pay a commitment fee of 0.25% to 0.50% per year on the unused availability under the bank credit facility, depending upon utilization.
The bank credit facility contains various restrictive covenants and other usual and customary terms and conditions of a revolving bank credit facility, including limitations on the payment of cash dividends and other restricted payments, limitations on the incurrence of additional debt, prohibitions on the sale of assets, and requirements for hedging a portion of the Company’s oil and natural gas production. Financial covenants require the Company to, among other things:
•
maintain a ratio, as of the last day of each fiscal quarter, of (a) current assets (excluding cash posted as collateral to secure hedging obligations) plus unused availability under the credit facility to (b) current liabilities (excluding the current portion of debt and the current portion of hedge liabilities) of not less than (i) 0.75 to 1.00 until June 30, 2004 and (ii) 1.00 to 1.00 thereafter;
•
maintain a ratio, as of the last day of each fiscal quarter, of (a) EBITDA (earnings before interest, taxes, depreciation, amortization and depletion) to (b) the sum of interest expense and maintenance capital expenditures for the period and 20% (on an annualized basis) of outstanding Tranche A advances, of not less than 1.20 to 1.00; and
•
maintain a ratio, as of the last day of each fiscal quarter, of (a) total debt to (b) EBITDA of not greater than 1.75 to 1.00 prior to the issuance by the Company of bonds as described in the credit agreement and 3.00 to 1.00 thereafter.
The bank credit facility also contains customary events of default, including the occurrence of a change of control or default in the payment or performance of any other indebtedness equal to or exceeding $2.0 million.
In connection with the merger with Forest Energy Resources on March 2, 2006, the Company amended and restated the existing bank credit facility to, among other things, increase maximum credit availability to $500 million, with a $400 million borrowing base as of that date, add an additional dedicated $40 million letter of credit facility, and add Mariner Energy Resources, Inc. as a co-borrower. Please see Note 9,
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
“Subsequent Events.” The financial covenants were modified under the amended and restated bank credit facility to require the Company to, among other things:
•
maintain a ratio of consolidated current assets plus the unused borrowing base to consolidated current liabilities of not less than 1.0 to 1.0; and
•
maintain a ratio of total debt to EBITDA of not more than 2.5 to 1.0.
The Company is in compliance with the financial covenants under the bank credit facility as of December 31, 2005.
As of December 31, 2005, $152.0 million was outstanding under the bank credit facility, and the weighted average interest rate was 7.15%. Net proceeds of approximately $38 million generated by the private placement in March 2005 were used to repay existing bank debt.
As of December 31, 2004, $105.0 million was outstanding under the bank credit facility, and the weighted average interest rate was 5.20%. The borrowing base under the bank credit facility is $135 million at December 31, 2004.
JEDI Term Promissory Note
As part of the Merger consideration payable to JEDI, the Company issued a term Promissory Note to JEDI in the amount of $10 million. The note matured on March 2, 2006, and bore interest, payable in kind at our option, at a rate of 10% per annum until March 2, 2005, and 12% per annum thereafter unless paid in cash in which event the rate remained 10% per annum. We chose to pay interest in cash rather than in kind. The JEDI note was secured by a lien on three of the Company’s non-proven, non-producing properties located in the Outer Continental Shelf of the Gulf of Mexico. The Company could offset against the note the amount of certain claims for indemnification that could be asserted against JEDI under the terms of the merger agreement. The JEDI term Promissory Note contained customary events of default, including the occurrence of an event of default under the Company’s bank credit facility.
In March 2005, the Company repaid $6.0 million of the note utilizing proceeds from the private placement in March 2005. The $4.0 million balance remaining on the JEDI note at December 31, 2005 was repaid in full on its maturity date of March 2, 2006.
Cash Interest Expense
Cash paid for interest was $6.1 million for 2005, $5.4 million and -0- million for 2004 Post-Merger and 2004 Pre-Merger, respectively, and $4.0 million for 2003.
5.
Stockholders’ Equity
We have adopted an Equity Participation Plan that provided for the one-time grant at the closing of our private equity placement on March 11, 2005 of 2,267,270 restricted shares of our common stock to certain of our employees. No further grants will be made under the Equity Participation Plan, although persons who receive such a grant will be eligible for future awards of restricted stock or stock options under our Amended and Restated Stock Incentive Plan described below. We intended the grants of restricted stock under the Equity Participation Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common stock. Therefore, Equity Participation Plan grantees did not pay any consideration for the common stock they received, and we received no remuneration
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
for the stock. Grantees are entitled to vote, and accrue dividends on, the restricted stock prior to vesting; provided, however that any dividends that accrue on the restricted stock prior to vesting will only be paid to grantees to the extent the restricted stock vests. In connection with the merger with Forest Energy Resources, (i) the 463,656 shares of restricted stock held by non-executive employees vested, and (ii) each of Mariner’s executive officers agreed, in exchange for a cash payment of $1,000, that his or her shares of restricted stock will not vest before the later of March 11, 2006 or ninety days after the effective date of the merger, which is May 31, 2006.
We adopted a Stock Incentive Plan which became effective March 11, 2005 and was amended and restated on March 2, 2006. Awards to participants under the Amended and Restated Stock Incentive Plan may be made in the form of incentive stock options, or ISOs, non-qualified stock options or restricted stock. The participants to whom awards are granted, the type or types of awards granted to a participant, the number of shares covered by each award, the purchase price, conditions and other terms of each award are determined by the Board of Directors or a committee thereof. A total of 6.5 million shares of Mariner’s common stock is subject to the Amended and Restated Stock Incentive Plan. No more than 2.85 million shares issuable upon exercise of options or as restricted stock can be issued to any individual. As of March 17, 2006, approximately 5.7 million shares remained available under the Amended and Restated Stock Incentive Plan for future issuance to participants. Unless sooner terminated, no award may be granted under the Amended and Restated Stock Incentive Plan after October 12, 2015.
For the two years ended December 31, 2004 and 2003, Mainer Energy, Inc. had no outstanding stock options. During the year ended December 31, 2005, we granted 2,267,270 shares of restricted stock and options to purchase 809,000 shares of stock. We also issued 3.6 million shares of common stock in March 2005 in connection with our private placement offering. The fair value of the restricted shares at date of grant has been recorded in stockholders’ equity as unearned compensation and is being amortized over the vesting period as compensation expense. We recorded compensation expense of $25.7 million in the year ended December 31, 2005 related to the restricted stock granted in 2005 and stock options outstanding as of December 31, 2005. The weighted average fair value of options granted during the year ended December 31, 2005 was $2.69. For the year ended December 31, 2004, we recorded no stock compensation expense related to either restricted stock or stock options.
The following table is a summary of stock option activity for the year ended and as of December 31, 2005:
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The following table summarizes certain information about stock options outstanding at December 31, 2005:
The following table summarizes shares of restricted stock granted for the year ended December 31, 2005:
6.
Employee Benefit And Royalty Plans
Employee Capital Accumulation Plan-The Company provides all full-time employees (who are at least 18 years of age) participation in the Employee Capital Accumulation Plan (the “Plan”) which is comprised of a contributory 401(k) savings plan and a discretionary profit sharing plan. Under the 401(k) feature, the Company, at its sole discretion, may contribute an employer-matching contribution equal to a percentage not to exceed 50% of each eligible participant’s matched salary reduction contribution as defined by the Plan. Under the discretionary profit sharing contribution feature of the Plan, the Company’s contribution, if any, must be determined annually and must be 4% of the lesser of the Company’s operating income or total employee compensation and shall be allocated to each eligible participant pro rata to his or her compensation. During the years ended December 31, 2005, 2004 and 2003, the Company contributed $240,650, $193,521 and $159,241, respectively, to the Plan related to the discretionary feature. Currently there are no plans to terminate the Plan.
Overriding Royalty Interests-Pursuant to agreements, certain employees and consultants of the Company are entitled to receive, as incentive compensation, overriding royalty interests (“Overriding Royalty Interests”) in certain oil and gas prospects acquired by the Company. Such Overriding Royalty Interests entitle the holder to receive a specified percentage of the gross proceeds from the future sale of oil and gas (less production taxes), if any, applicable to the prospects. Cash payments made by the Company to current employees and consultants with respect to Overriding Royalty Interests were $2.6 million for 2005, $2.5 million and $0.2 million for 2004 Post-Merger and 2004 Pre-Merger, respectively, and $2.0 million for 2003.
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
7.
Commitments And Contingencies
Minimum Future Lease Payments-The Company leases certain office facilities and other equipment under long-term operating lease arrangements. Minimum rental obligations under the Company’s operating leases in effect at December 31, 2005 are as follows (in thousands):
Rental expense, before capitalization, was approximately $509,000 for 2005, $486,000 and $78,000 for 2004 Post-Merger and 2004 Pre-Merger, respectively, and $569,000 for 2003.
Hedging Program-The energy markets have historically been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. In an effort to reduce the effects of the volatility of the price of oil and natural gas on the Company’s operations, management has elected to hedge oil and natural gas prices from time to time through the use of commodity price swap agreements and costless collars. While the use of these hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements.
As of December 31, 2005, the Company had the following fixed price swaps outstanding:
As of December 31, 2005, the Company had the following costless collars outstanding:
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The Company has not entered into any hedge transactions subsequent to December 31, 2005.
As of December 31, 2004, the Company had the following fixed price swaps outstanding:
As of December 31, 2004, the Company had the following costless collars outstanding:
The Company has reviewed the financial strength of its counterparties and believes the credit risk associated with these swaps and costless collars to be minimal.
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The following table sets forth the results of hedging transactions during the periods indicated:
The Company’s hedge transactions resulted in a $53.8 million loss for 2005 and a $28.4 million loss for 2004 Post-Merger and a $0.7 million gain for 2004 Pre-Merger. $4.5 million of the 2005 loss and $7.9 million of the Post-Merger loss relates to the hedge liability recorded at the merger date. In addition, in 2003 the Company recorded $3.2 million of expense related to the settlement of derivatives that were not accounted for as hedges.
Other Commitments-In the ordinary course of business, the Company enters into long-term commitments to purchase seismic data. The minimum annual payments under these contracts are $14.5 and $6.5 million in 2006 and 2007, respectively. In 2005, the Company entered into a joint exploration agreement granting the joint venture partner the right to participate in prospects covered by certain seismic data licensed by the Company in return for $6.0 million in scheduled payments to be received by the Company over a two-year period. Subsequent to December 31, 2005, the Company entered into four additional long-term commitments to purchase seismic data in the amount of $26.9 million.
Deepwater Rig-In February 2000, the Company and Noble Drilling Corporation entered into an agreement whereby the Company committed to using a Noble deepwater rig for a minimum of 660 days over a five-year period. The Company assigned to Noble working interests in seven of the Company’s deepwater exploration prospects and agreed to pay Noble’s share of certain costs of drilling the initial test well on the prospects. As of December 31, 2003, the Company had no further obligation under the agreement for the use of the rig and had drilled five of the seven prospects. Subsequent to year end 2003, the Company and Noble Drilling Corporation agreed to exchange Noble’s interest in one of the two remaining undrilled prospects for an interest in another prospect drilled in the first quarter of 2004 and exchange Noble’s carried working interest in the other remaining undrilled prospect for a larger un-carried working interest in the prospect, and the Company agreed to use one of two Noble drilling rigs for an aggregate of 75 days. Mariner has no further obligations under this agreement.
MMS Appeal-Mariner operates numerous properties in the Gulf of Mexico. Two of such properties were leased from the Mineral Management Service subject to the 1996 Royalty Relief Act. This Act relieved the obligation to pay royalties on certain leases until a designated volume is produced. These leases contained language that limited royalty relief if commodity prices exceeded predetermined levels. For the years 2000, 2001, 2003, 2004 and 2005, commodity prices exceeded the predetermined levels. The Company believes the
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
MMS did not have the authority to set pricing limits in these leases and has filed an administrative appeal with the MMS regarding this matter and withheld payment of royalties on the leases. The Company has recorded a liability for 100% of the exposure on this matter which on December 31, 2005 was $16.0 million. In April 2005, the MMS denied the administrative appeal. On October 3, 2005, we filed suit in the U.S. District Court for the Southern District of Texas seeking judicial review of the dismissal of our appeal by the Board of Land Appeals.
Insurance Matters-In September 2004, the Company incurred damage from Hurricane Ivan that affected its Mississippi Canyon 66 (Ochre) and Mississippi Canyon 357 fields. Production from Mississippi Canyon 357 was shut-in until March 2005, when necessary repairs were completed and production recommenced. Production from Ochre is currently shut-in awaiting rerouting of umbilical and flow lines to another host platform. Prior to Hurricane Ivan, this field was producing at a net rate of approximately 6.5 MMcfe per day. Production from Ochre is expected to recommence in the second quarter of 2006. In addition, a semi-submersible rig on location at the Company’s Viosca Knoll 917 (Swordfish) field was blown off location by the hurricane and incurred damage. Until we are able to complete all the repair work and submit costs to the insurance underwriters for review, the full extent of our insurance recovery and the resulting net cost to the Company is unknown. We expect the net cost to the Company to be at least equal to the amount of our annual deductible of $1.25 million plus the single occurrence deductible of $.375 million.
In August 2005 and September 2005, Mariner incurred damage from Hurricanes Katrina and Rita that affected several of its offshore fields. Hurricane Katrina caused minor damage to our owned platforms and facilities. Production that was shut-in by the hurricane was recommenced within three weeks of the hurricane, with the exception of two minor non-operated fields. However, Hurricane Katrina inflicted damage to host facilities for our Pluto, Rigel and Ochre projects that is expected to delay start-up of these projects until the second quarter of 2006 for Pluto and Ochre. Rigel production began in the first quarter of 2006. Hurricane Rita caused minor damage to our owned platforms and some damage to certain host facilities of our development projects. Production shut-in as a result of Hurricane Rita fully recommenced within three weeks of the hurricane, with the exception of one minor field. We cannot estimate a range of loss arising from the hurricanes until we are able to more completely assess the impacts on our properties and the properties of our operational partners. Until we are able to complete all the repair work and submit costs to our insurance underwriters for review, the full extent of our insurance recovery and the resulting net cost to us for Hurricanes Katrina and Rita will be unknown. For the insurance period ending September 30, 2005, we carried a $3.0 million annual deductible and a $.375 million single occurrence deductible.
Effective March 2, 2006, Mariner has been accepted as a member of OIL Insurance, Ltd., or OIL, an industry insurance cooperative, through which the assets of both Mariner and the Forest Gulf of Mexico operations are insured. The coverage contains a $5 million annual per occurrence deductible for the combined assets and a $250 million per occurrence loss limit. However, if a single event causes losses to OIL insured assets in excess of $1 billion in the aggregate (effective June 1, 2006, such amount will be reduced to $500 million), amounts covered for such losses will be reduced on a pro rata basis among OIL members. Pending review of our insurance program, we have maintained our commercially underwritten insurance coverage for the pre-merger Mariner assets which expires on September 30, 2006. This coverage contains a $3 million annual deductible and a $500,000 occurrence deductible, $150 million of aggregate loss limits, and limited business interruption coverage. While the coverage remains in effect, it will be primary to the OIL coverage for the pre-merger Mariner assets.
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
Litigation-The Company, in the ordinary course of business, is a claimant and/or a defendant in various legal proceedings, including proceedings as to which the Company has insurance coverage. The Company does not consider its exposure in these proceedings, individually and in the aggregate, to be material.
8.
Income Taxes
The components of the federal income tax provision are:
The following table sets forth a reconciliation of the statutory federal income tax with the income tax provision (in thousands):
Federal income taxes of $1.6 million were paid by the Company for the 2004 Post-Merger period for alternative minimum tax liability, and no federal income taxes were paid by the Company in the years ended December 31, 2003 and 2005. An income tax benefit of $1,045,000 was included as a reduction in “Change in Accounting Principle” for the adoption of SFAS No. 143 in 2003.
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The Company’s deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Significant components of the deferred tax assets and liabilities are as follows (in thousands):
At December 31, 2005, the Company had federal and state net operating loss carryforwards of approximately $129,059 and $7,055, respectively, which will expire in varying amounts between 2018 and 2025 and are subject to certain limitations on an annual basis. A valuation allowance has been established against net operating losses where it is more likely than not that such losses will expire before they are utilized.
9.
Subsequent Events
On March 2, 2006, we completed a merger transaction with Forest Energy Resources (the Forest Transaction). Prior to the consummation of the merger, Forest transferred and contributed the assets and certain liabilities associated with its offshore Gulf of Mexico operations to Forest Energy Resources. Immediately prior to the merger, Forest distributed all of the outstanding shares of Forest Energy Resources to Forest shareholders on a pro rata basis. Forest Energy Resources then merged with a newly formed subsidiary of Mariner, and became a new wholly owned subsidiary of Mariner. Immediately following the merger, approximately 59% of the Mariner common stock was held by shareholders of Forest and approximately 41% of Mariner common stock was held by the pre-merger stockholders of Mariner. In the merger Mariner issued 50,637,010 shares of common stock to Forest shareholders.
The sources and uses of funds related to the Forest Transaction were as follows:
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
In addition, approximately $3.8 million in merger-related costs were funded from bank loan proceeds prior to the closing of the transaction.
Mariner Energy, Inc. is the acquiring entity in accordance with the provisions of Statement of Financial Accounting Standards No. 141, Business Combinations (“SFAS 141”). As a results, the assets and liabilities acquired by Mariner in the Forest Transaction will be adjusted to their estimated fair values as of the effective date of the transaction (March 2, 2006).
The initial fair value estimate of the underlying assets and liabilities acquired is determined by estimating the value of the underlying proved reserves at the transaction date plus or minus the fair value of other assets and liabilities, including inventory, unproved oil and gas properties, gas imbalances, debt (at face value), derivatives, and abandonment liabilities. The final purchase price allocation will be determined after closing based on the actual fair value of current assets, current liabilities, indebtedness, long-term liabilities, proven and unproved oil and gas properties and identifiable intangible assets. We are continuing to evaluate all of these items; accordingly, the final purchase price may differ in material respects from that presented below. Carryover basis accounting applies for tax purposes. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the March 2, 2006 transaction date:
(1)
Represents deferred income taxes recorded at the date of the transaction due to differences between the book basis and the tax basis of assets. For book purposes, the assets of the Forest Gulf of Mexico operations had a step-up in basis while the existing tax basis carried over.
On March 2, 2006, Mariner and Mariner Energy Resources, Inc. entered into a $500 million senior secured revolving credit facility, and an additional $40 million senior secured letter of credit facility. The revolving credit facility will mature on March 2, 2010, and the $40 million letter of credit facility will mature on March 2, 2009. Mariner used borrowings under the revolving credit facility to facilitate the merger and to retire existing debt, and we may use borrowings in the future for general corporate purposes. The $40 million letter of credit facility has been used to obtain a letter of credit in favor of Forest to secure Mariner’s performance of its obligations under an existing drill-to-earn program. The outstanding principal balance of loans under the revolving credit facility may not exceed the borrowing base, which initially has been set at $400 million. If the borrowing base falls below the outstanding balance under the revolving credit facility, Mariner will be required to prepay the deficit, pledge additional unencumbered collateral, repay the deficit and cash collateralize certain letters of credit, or effect some combination of such prepayment, pledge and repayment and collateralization.
As part of the Merger consideration payable to JEDI, the Company issued a term Promissory Note to JEDI in the amount of $10 million. The note matured on March 2, 2006, and bore interest, payable in kind at our option, at a rate of 10% per annum until March 2, 2005, and 12% per annum thereafter unless paid in
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
cash in which event the rate remained 10% per annum. In March 2005, the Company repaid $6.0 million of the note utilizing proceeds from the private placement in March 2005. The $4.0 million balance remaining on the JEDI note at December 31, 2005 was repaid in full on its maturity date of March 2, 2006.
Effective March 2, 2006, Mariner has been accepted as a member of OIL, an industry insurance cooperative, through which the assets of both Mariner and the Forest Gulf of Mexico operations are insured. The coverage contains a $5 million annual per occurrence deductible for the combined assets and a $250 million per occurrence loss limit. However, if a single event causes losses to OIL insured assets in excess of $1 billion in the aggregate (effective June 1, 2006, such amount will be reduced to $500 million), amounts covered for such losses will be reduced on a pro rata basis among OIL members. Pending review of its insurance program, the Company has maintained our commercially underwritten insurance coverage for the pre-merger Mariner assets which expires on September 30, 2006. This coverage contains a $3 million annual deductible and a $500,000 occurrence deductible, $150 million of aggregate loss limits, and limited business interruption coverage. While the coverage remains in effect, it will be primary to the OIL coverage for the pre-merger Mariner assets.
The Company has adopted an Equity Participation Plan that provided for the one-time grant at the closing of our private equity placement on March 11, 2005 of 2,267,270 restricted shares of our common stock to certain of our employees. In connection with the merger with Forest Energy Resources on March 2, 2006, (i) the 463,656 shares of restricted stock held by non-executive employees vested, and (ii) each of Mariner’s executive officers agreed, in exchange for a cash payment of $1,000, that his or her shares of restricted stock will not vest before the later of March 11, 2006 or ninety days after the effective date of the merger, which is May 31, 2006.
The Company adopted a Stock Incentive Plan which became effective March 11, 2005 and was amended and restated on March 2, 2006. A total of 6.5 million shares of Mariner’s common stock is subject to the Amended and Restated Stock Incentive Plan. No more than 2.85 million shares issuable upon exercise of options or as restricted stock can be issued to any individual. As of March 17, 2006, approximately 5.7 million shares remained available under the Amended and Restated Stock Incentive Plan for future issuance to participants. Unless sooner terminated, no award may be granted under the Amended and Restated Stock Incentive Plan after October 12, 2015.
10.
Oil and Gas Producing Activities and Capitalized Costs (Unaudited)
The results of operations from the Company’s oil and gas producing activities were as follows (in thousands):
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The following table summarizes the Company’s capitalized costs of oil and gas properties.
Costs incurred in property acquisition, exploration and development activities were as follows (in thousands, except per equivalent mcf amounts):
The Company capitalizes internal costs associated with exploration activities in progress. These capitalized costs were approximately 35%, 46% and 48% of the Company’s gross general and administrative expenses, excluding stock compensation expense for the years ended December 31, 2005, 2004 and 2003, respectively.
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The following table summarizes costs related to unevaluated properties that have been excluded from amounts subject to amortization at December 31, 2005. Three relatively significant projects were included in unproved properties with balances of $6.0 million, $5.8 million and $5.5 million at December 31, 2005. These projects are expected to be evaluated within the next twelve months. The Company regularly evaluates these costs to determine whether impairment has occurred. The majority of these costs are expected to be evaluated and included in the amortization base within three years.
All of the excluded costs at December 31, 2005 relate to activities in the Gulf of Mexico.
11.
Supplemental Oil and Gas Reserve and Standardized Measure Information (Unaudited)
Estimated proved net recoverable reserves as shown below include only those quantities that are expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved developed reserves represent only those reserves expected to be recovered through existing wells. Proved undeveloped reserves include those reserves expected to be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure is required for recompletion. Also included in the Company’s proved undeveloped reserves as of December 31, 2005 were reserves expected to be recovered from wells for which certain drilling and completion operations had occurred as of that date, but for which significant future capital expenditures were required to bring the wells into commercial production.
Reserve estimates are inherently imprecise and may change as additional information becomes available. Furthermore, estimates of oil and gas reserves, of necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of such data as well as in the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. There also can be no assurance that the reserves set forth herein will ultimately be produced or that the proved undeveloped reserves set forth herein will be developed within the periods anticipated. It is likely that variances from the estimates will be material. In addition, the estimates of future net revenues from proved reserves of the Company and the present value thereof are based upon certain assumptions about future production levels, prices and costs that may not be correct when judged against actual subsequent experience. The Company emphasizes with respect to the estimates prepared by independent petroleum engineers that the discounted future net cash flows should not be
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
construed as representative of the fair market value of the proved reserves owned by the Company since discounted future net cash flows are based upon projected cash flows which do not provide for changes in oil and natural gas prices from those in effect on the date indicated or for escalation of expenses and capital costs subsequent to such date. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Actual results will differ, and are likely to differ materially, from the results estimated.
ESTIMATED QUANTITIES OF PROVED RESERVES
ESTIMATED QUANTITIES OF PROVED DEVELOPED RESERVES
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The following is a summary of a Standardized Measure of discounted net future cash flows related to the Company’s proved oil and gas reserves. The information presented is based on a calculation of proved reserves using discounted cash flows based on year-end prices, costs and economic conditions and a 10% discount rate. The additions to proved reserves from new discoveries and extensions could vary significantly from year to year. Additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, the information presented below should not be viewed as an estimate of the fair value of the Company’s oil and gas properties, nor should it be considered indicative of any trends.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
During recent years, there have been significant fluctuations in the prices paid for crude oil in the world markets and in the United States, including the posted prices paid by purchasers of the Company’s crude oil. The NYMEX prices of oil and gas at December 31, 2005, 2004 and 2003, used in the above table, were $61.04, $43.45 and $32.52 per Bbl, respectively, and $10.05, $6.15 and $5.96 per Mmbtu, respectively, and do not include the effect of hedging contracts in place at period end.
MARINER ENERGY, INC.
NOTES TO THE FINANCIAL STATEMENTS - (Continued)
For the Year Ended December 31, 2005,
for the Period from March 3, 2004 through December 31, 2004 (Post-Merger),
for the Period from January 1, 2004 through March 2, 2004 (Pre-Merger),
and For the Year Ended December 31, 2003
The following are the principal sources of change in the Standardized Measure of discounted future net cash flows (in thousands):
12.
Unaudited Quarterly Financial Information
The following table presents Mariner’s unaudited quarterly financial information for 2005 and 2004:
(1)
The sum of quarterly net income per share may not agree with total year net income per share, as each quarterly computation is based on the weighted average shares outstanding.
(2)
Restated for the 1,380 to 29,748,130 stock split, effective March 3, 2005.
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosures.
None
Item 9A.
Item 9A.
Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Mariner, under the supervision and with the participation of its management, including the Mariner’s principal executive officer and principal financial officer, evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation, our principal executive officer and principal financial officer concluded that Mariner’s disclosure controls and procedures are effective.
Changes in Internal Controls Over Financial Reporting.
There were no changes that occurred during the fourth quarter of the fiscal year covered by this Annual Report on Form 10-K that have materially affected, or are reasonably likely to materially affect, our 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.
The Board of Directors of Mariner is composed of six directors. The board will be increased to seven and an additional director will be mutually agreed by Mariner and Forest on or prior to March 31, 2006.
The following table sets forth the names, ages (as of March 17, 2006) and titles of the individuals who are the directors and executive officers of Mariner. All directors are elected for terms in accordance with their class, as described in “- Board of Directors” below. All executive officers hold office until their successors are elected and qualified. There are no family relationships among any of our directors or executive officers.
Scott D. Josey - Mr. Josey has served as Chairman of the Board since August 2001. Mr. Josey was appointed Chief Executive Officer in October 2002 and President in February 2005. From 2000 to 2002, Mr. Josey served as Vice President of Enron North America Corp. and co-managed its Energy Capital Resources group. From 1995 to 2000, Mr. Josey provided investment banking services to the oil and gas industry and portfolio management services. From 1993 to 1995, Mr. Josey was a Director with Enron Capital & Trade Resources Corp. in its energy investment group. From 1982 to 1993, Mr. Josey worked in all phases of drilling, production, pipeline, corporate planning and commercial activities at Texas Oil and Gas Corp. Mr. Josey is a member of the Society of Petroleum Engineers and the Independent Producers Association of America.
Dalton F. Polasek - Mr. Polasek was appointed Chief Operating Officer in February 2005. From April 2004 to February 2005, Mr. Polasek served as Executive Vice President - Operations and Exploration. From February 2001 to October 2001, Mr. Polasek was self-employed. From October 2001 to April 2004, Mr. Polasek served as Senior Vice President - Operations. Prior to joining Mariner, Mr. Polasek served as: Vice President of Gulf Coast Engineering for Basin Exploration, Inc. from 1996 until February 2001; Vice President of Engineering for SMR Energy from 1994 to 1996; director of Gulf Coast Acquisitions and Engineering for General Atlantic Resources, Inc. from 1991 to 1994; and manager of planning and business development for Mark Producing Company from 1983 to 1991. He began his career in 1975 as a reservoir engineer for Amoco Production Company. Mr. Polasek is a Registered Professional Engineer in Texas and a member of the Independent Producers Association of America, the American Association of Drilling Engineers and the American Petroleum Institute.
Rick G. Lester - Mr. Lester joined Mariner as Vice President, Chief Financial Officer and Treasurer in October 2004. From January 2004 to October 2004, Mr. Lester was self-employed as a consultant. From 1998 to 2003, Mr. Lester was the Executive Vice President, CFO and Treasurer of Contour Energy Company (which filed for Chapter 11 bankruptcy protection in July 2002 and emerged from bankruptcy in December 2002). From 1991 to 1998, Mr. Lester held the positions of Vice President, CFO and Treasurer for Domain Energy Corporation and its Tenneco Ventures predecessor. Prior to 1991, he held various positions with Tenneco, Inc. and Tenneco Exploration and Production including Corporate Finance Manager, International Tax Manager and Business Division Accounting Manager. Mr. Lester has over 30 years of industry experience and is a Certified Public Accountant.
Jesus G. Melendrez - Mr. Melendrez has served as Vice President - Corporate Development since July 2003. Mr. Melendrez also served as a director of Mariner from April 2000 to July 2003. From February 2000 until July 2003, Mr. Melendrez was a Vice President of Enron North America Corp. in the Energy Capital Resources group where he managed the group’s portfolio of oil and gas investments. He was a Senior Vice President of Trading and Structured Finance with TXU Energy Services from 1997 to 2000, and from 1992 to 1997, Mr. Melendrez was employed by Enron in various commercial positions in the areas of domestic oil and gas financing and international project development. From 1980 to 1992, Mr. Melendrez was employed by Exxon in various reservoir engineering and planning positions.
Mike C. van den Bold - Mr. van den Bold was appointed Vice President and Chief Exploration Officer in April 2004. From October 2001 to April 2004, he served as Vice President - Exploration. Mr. van den Bold joined Mariner in July 2000 as Senior Development Geologist. From 1996 to 2000, Mr. van den Bold worked for British-Borneo Oil & Gas plc. He began his career at British Petroleum. Mr. van den Bold has over 17 years of industry experience. He is a Certified Petroleum Geologist, Texas Board Certified Geologist and member of the American Association of Petroleum Geologists.
Teresa G. Bushman - Ms. Bushman joined Mariner as Vice President, General Counsel and Secretary in June 2003. From 1996 until joining Mariner in 2003, Ms. Bushman was employed by Enron North America Corp., most recently as Assistant General Counsel representing the Energy Capital Resources group, which provided debt and equity financing to the oil and gas industry. Prior to joining Enron, Ms. Bushman was a partner with Jackson Walker, LLP, in Houston.
Judd A. Hansen - Mr. Hansen has served as Vice President - Shelf and Onshore since February 2002. From October 2001 to February 2002, Mr. Hansen was self-employed as a consultant. From 1997 until March
2001, Mr. Hansen was employed as Operations Manager of the Gulf Coast Division for Basin Exploration, Inc. From 1991 to 1997, he was employed in various engineering positions at Greenhill Petroleum Corporation, including Senior Production Engineer and Workover/Completion Superintendent. Mr. Hansen started his career with Shell Oil Company in 1978 and has 27 years of experience in conducting operations in the oil and gas industry.
Cory L. Loegering - Mr. Loegering has served as Vice President - Deepwater since August 2002. Mr. Loegering joined Mariner in July 1990 and since 1998 has held various positions including Vice President of Petroleum Engineering and Director of Deepwater development. Mr. Loegering was employed by Tenneco from 1982 to 1989, in various positions including as senior engineer in the economic, planning and analysis group in Tenneco’s corporate offices. Mr. Loegering began his career with Conoco in 1977 and held positions in the construction, production and reservoir departments responsible for Gulf of Mexico production and development. Mr. Loegering has 29 years of experience in the industry.
Bernard Aronson - Mr. Aronson was elected as a director in March 2004. He is a founding partner of ACON Investments, a private equity fund. Prior to founding ACON Investments in 1996, Mr. Aronson was International Advisor to Goldman Sachs & Co. for Latin America from 1994 to 1996. From 1989 through 1993, Mr. Aronson served as Assistant Secretary of State for Inter-American Affairs. He is a member of the Council on Foreign Relations and the President’s Advisory Commission on Trade Promotions and Negotiations. Mr. Aronson currently serves on the boards of directors of Liz Claiborne, Inc., Royal Caribbean International Inc., Tropigas S.A. and Hyatt International Corp.
Jonathan Ginns - Mr. Ginns was elected as a director in March 2004. He is a founding partner of ACON Investments. Prior to founding ACON Investments, a private equity fund, in 1996, Mr. Ginns served as a Senior Investment Officer for the Global Environment-Emerging Markets Fund, part of the GEF Funds group, from 1994 to 1995. Mr. Ginns currently serves on the boards of directors of The Optimal Group, Signal International, and Tropigas S.A.
John F. Greene - Mr. Greene was elected as a director in August 2005. He served as Executive Vice President of Worldwide Exploration, Production and Natural Gas Marketing at Louisiana Land & Exploration Company before his retirement in 1995. Prior to joining Louisiana Land & Exploration Company, Mr. Greene was the President and Chief Executive Officer of Milestone Petroleum, Inc. (today, Burlington Resources, Inc.) from 1981 to 1985. Mr. Greene served on the board of directors of Colorado-Wyoming Reserves Company from 1998 through 2004 and as a director and member of the compensation committee of Basin Exploration, Inc. from 1996 through 2001. Mr. Greene began his career at Conoco and served in the United States Navy from 1963 until 1986. He is currently a partner and director of The Shoreline Company and Leaf River Resources.
H. Clayton Peterson - Mr. Peterson was elected a director in March 2006. During his 33-year career with Arthur Andersen, he specialized in audits of oil and gas companies. Most recently, from January 2000 to September 2002, Mr. Peterson was Managing Partner of the Denver office of Arthur Andersen and Regional Managing Partner of the audit practices of Arthur Andersen in Tulsa, Oklahoma City and Dallas. Since September 2002, Mr. Peterson has been a business consultant, including to the Estate of Kim Magness from August 2003 to present. He has been a member of the board of directors of RE/MAX International, Inc. since May 2005 and is co-chair of its audit committee.
John L. Schwager - Mr. Schwager was elected as a director in August 2005. Prior to his retirement in 2004, Mr. Schwager served as Chief Executive Officer and President of Belden & Blake Corporation. Before joining Belden & Blake Corporation in 1999, Mr. Schwager was the founder and served as President of AnnaCarol Enterprises, Inc., a consulting firm that provided planning, advisory, evaluation and management services to the energy industry. From 1984 until 1997 he served in several management roles, including President and Chief Executive Officer at Alamco, Inc. From 1970 through 1984, Mr. Schwager held various engineering, operations, management and executive officer positions with Callon Petroleum Company and Shell Oil Company.
Board of Directors
Under the terms of the Forest Energy Resources merger agreement, as amended, the Board of Directors of Mariner after completion of the merger is to be composed initially of seven individuals, five of whom were directors of Mariner immediately prior to the merger, one of whom, Mr. Peterson, was mutually agreed upon by Mariner and Forest prior to, and became a director upon, completion of the merger, and one of whom is to be mutually agreed upon by Mariner and Forest on or before April 1, 2006.
Our certificate of incorporation and bylaws provide for a classified board of directors consisting of three classes of directors, each serving staggered three-year terms. As a result, stockholders will elect a portion of our Board of Directors each year. The Class I directors’ term will expire at the annual meeting of stockholders to be held in 2009, Class II directors’ terms will expire at the annual meeting of stockholders to be held in 2007 and Class III directors’ terms will expire at the annual meeting of stockholders to be held in 2008. Currently, the Class I directors are Messrs. Aronson and Peterson, the Class II directors are Messrs. Greene and Schwager, and the Class III directors are Messrs. Ginns and Josey. Effective upon completion of the merger, the directors increased the board to six and elected Mr. Peterson to fill the vacancy. Pursuant to provisions in our certificate of incorporation regarding vacancies on the Board of Directors, Mr. Peterson must stand for reelection at the next annual stockholders meeting for a term expiring at the 2009 annual stockholders meeting. At each annual meeting of stockholders held after the initial classification, the successors to directors whose terms will then expire will be elected to serve from the time of election until the third annual meeting following election. The division of our Board of Directors into three classes with staggered terms may delay or prevent a change of our management or a change in control.
In addition, our bylaws provide that the authorized number of directors, which shall constitute the whole Board of Directors, may be changed by resolution duly adopted by the Board of Directors. Any additional directorships resulting from an increase in the number of directors will be distributed among the three classes so that, as nearly as possible, each class will consist of one-third of the total number of directors. Vacancies and newly created directorships may be filled by the affirmative vote of a majority of our directors then in office, even if less than a quorum.
Committees of the Board
Our Board of Directors has established four committees, the audit committee, the compensation committee, the nominating and corporate governance committee, and the executive committee.
Each of Messrs. Aronson, Ginns and Peterson (Chairman) is a member of our audit committee and is “independent” under the listing standards of New York Stock Exchange and SEC rules. In addition, the Board of Directors has determined that Mr. Peterson is an “audit committee financial expert,” as defined under the rules of the SEC. The audit committee recommends to the Board of Directors the independent public accountants to audit our financial statements and oversees the annual audit. The committee also approves any other services provided by public accounting firms. The audit committee provides assistance to the Board of Directors in fulfilling its oversight responsibility to the stockholders, the investment community and others relating to the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence, and the performance of our internal audit function. The committee oversees our system of disclosure controls and procedures and system of internal controls regarding financial, accounting, legal compliance and ethics that management and the Board of Directors have established. In doing so, it is the responsibility of the committee to maintain free and open communication between the committee and our independent auditors, the internal accounting function and management of Mariner.
Each of Messrs. Aronson (Chairman) and Greene serves on the nominating and corporate governance committee of our Board of Directors and is “independent” under the listing standards of the New York Stock Exchange and SEC rules. This committee nominates candidates to serve on our Board of Directors and approves director compensation. The committee also is responsible for monitoring a process to assess board effectiveness, developing and implementing our corporate governance guidelines and in taking a leadership role in shaping the corporate governance of Mariner.
Each of Messrs. Ginns, Greene and Schwager (Chairman) serves on the compensation committee of our Board of Directors and is “independent” under the listing standards of the New York Stock Exchange and SEC rules. The compensation committee reviews the compensation and benefits of our executive officers, establishes and reviews general policies related to our compensation and benefits, and administers our Equity Participation Plan and Amended and Restated Stock Incentive Plan. Under the compensation committee charter, the compensation committee determines the compensation of our CEO.
Each of Messrs. Ginns, Josey (Chairman), Peterson and Schwager serves on the executive committee of our Board of Directors. The executive committee may exercise the powers and authority of the Board in managing the business and affairs of the Company when the Board is not in session, subject to our certificate of incorporation, applicable law and any limits on authority determined from time to time by the Board.
Mariner makes periodic SEC filings, including its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and if applicable amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. These filings are available free of charge through Mariner’s website at www.mariner-energy.com as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC. Additionally, Mariner makes available free of charge on its website at www.mariner-energy.com:
•
its audit committee charter;
•
its nominating and corporate governance committee charter;
•
its compensation committee charter;
•
its code of ethics; and
•
its corporate governance guidelines.
Any stockholder who so requests may obtain a printed copy of any of these documents from Mariner.
Mariner has adopted a written Code of Business Conduct and Ethics, a copy of which is publicly available on Mariner’s website at www.mariner-energy.com. Any amendments to, or waivers from the Code of Business Conduct and Ethics that apply to our executive officers and directors will be posted on the “Corporate Governance” section of our Internet web site located at www.mariner-energy.com.
Executive Sessions. The non-management directors of Mariner plan to meet in executive session at each regularly scheduled board meeting in 2006. The non-management directors have designated Mr. Aronson as the presiding director for their respective meetings. Stockholders or other interested persons may send communications to the presiding director or the non-management directors by writing to Mariner Energy, Inc., One BriarLake Plaza, Suite 2000, 2000 West Sam Houston Parkway South, Houston, Texas 77042, Attn: Corporate Secretary.
Section 16(a) Beneficial Ownership Reporting Compliance
Our directors and officers, and persons who own more than 10% of our common stock, became subject to Section 16(a) of the Exchange Act in February 2006. Section 16(a) requires these persons to file initial reports of ownership and reports of changes in ownership with the SEC and the New York Exchange. These persons are required by the Exchange Act to furnish us with copies of all Section 16(a) forms they file.
Item 11.
Item 11.
Executive Compensation.
Executive Compensation
The following table shows the annual compensation for our chief executive officer and the four other most highly compensated executive officers for the three fiscal years ended December 31, 2005.
Summary Compensation Table
(1)
As of March 30, 2006, bonuses for 2005 have not yet been paid.
(2)
Dollar amounts are calculated by multiplying the number of shares of common stock awarded by $14, the trading price of our common stock on the business day immediately preceding the date the award was granted. Grantees are entitled to vote, and accrue dividends on, the restricted stock prior to vesting; provided, that any dividends that accrue on the restricted stock prior to vesting will only be paid to grantees to the extent the restricted stock vests. Except in specified circumstances, the restricted shares will be automatically forfeited in the event a grantee’s employment terminates prior to the vesting date of the awards. The restricted stock granted will vest, and restrictions will terminate, on the later of (i) the first anniversary of the grant date, which was March 11, 2005, and (ii) the occurrence of a “Public Sale Date”, as defined in our Equity Participation Plan; but in no event later than the second anniversary of the date of grant. Notwithstanding this vesting schedule, the unvested shares of restricted stock will become fully vested upon death or disability of the employee, or if employment is terminated by us for reasons other than for “cause,” or if the employee elects to terminate employment with “good reason,” or upon the occurrence of a “change of control,” as those terms are defined in the agreement with us governing the grant. In connection with the merger, each of Mariner’s executive officers has agreed, in exchange for a cash payment of $1,000, that his or her shares of restricted stock will not vest before the later of March 11, 2006 or ninety days after the effective date of the merger, which is May 31, 2006. For additional information regarding these special long-term grants, please see “ - Equity Participation Plan.”
At December 31, 2005, the value of all restricted stock held by each named executive (based on the $17.75 trading price of our common stock on December 31, 2005) was as follows:
(3)
Amounts shown reflect insurance premiums paid by us with respect to term life insurance for the benefit of the named executive officers and retention payments paid during the year. The amounts for 2005 for Messrs. Josey, Polasek, van den Bold, and Lester and Ms. Bushman include $7,000 of employer matching contributions made pursuant to our 401(k) plan and $8,400 made pursuant to the profit sharing portion of our 401(k) plan. In addition, the 2005 amount for Mr. Josey includes $810 of insurance premiums under our group term life insurance. The 2005 amount for Mr. Polasek also includes $1,226 of insurance premiums under our group term life insurance. The 2005 amount for Mr. van den Bold also includes $419 of insurance premiums under our group term life insurance. The 2005 amount for Mr. Lester also includes $963 of insurance premiums under our group term life insurance. The 2005 amount for Ms. Bushman includes $1,797 of insurance premiums under our group term life insurance.
Employment Agreements and Other Arrangements
We have entered into an employment agreement with each of the current executive officers named in the above compensation table. Each employment agreement has an initial term that runs through March 2, 2007. The employment agreements automatically renew each March 3 for an additional one-year period unless prior notice is given. Each employment agreement provides for a base salary, a discretionary bonus, and participation in our benefit plans and programs. Mr. Josey’s agreement also provides for life insurance equal to two times his base salary.
Under the employment agreements, the officers are entitled to the following severance benefits in the event of a resignation for good reason, a termination without cause or, in the case of Mr. Josey’s agreement, our non-renewal of the agreement: (i) a payment equal to 18 months of salary continuation (two years for Mr. Josey and Mr. Polasek) at the highest rate in effect prior to termination, (ii) health care coverage for a period of eighteen months (two years for Mr. Josey and Mr. Polasek), (iii) an amount equal to the sum of all bonuses paid to the officer in the year prior to the year in which termination occurs, (iv) 100% vesting of all restricted shares under our Equity Participation Plan, and (v) 50% vesting of all other rights under any other equity plans, including our Amended and Restated Stock Incentive Plan.
The employment agreements also provide for certain change of control benefits. Upon termination for any reason other than cause at any time within nine months after a change of control that occurs while the executive is employed, or upon the occurrence of a change of control within nine months following resignation of employment for good reason or termination without cause, the agreements provide for the following benefits: (i) a lump sum payment equal to 2.0 (2.5 for Mr. Polasek and 2.99 for Mr. Josey) times the sum of the officer’s base salary and three year average annual bonus, and (ii) 100% vesting of all rights under any equity plans, including our Equity Participation Plan and our Amended and Restated Stock Incentive Plan. The officers are entitled to a full tax gross-up payment if the aggregate payments and benefits to be provided constitute a “parachute payment” subject to a Federal excise tax.
The executive officers of Mariner are entitled to receive cash payments of $1,000 each in exchange for the waiver of certain rights under their employment agreements, including the automatic vesting or acceleration of restricted stock and options upon the completion of the merger with Forest Energy Resources and the right to receive a lump sum cash payment if the officer voluntarily terminates employment without good reason within nine months following the completion of the merger.
The agreements also include confidentiality and non-solicitation provisions.
Overriding Royalty Arrangements
Mariner’s geologist and geophysicist employees are eligible to participate in Mariner’s Amended and Restated Gulf of Mexico Overriding Royalty Interest Plan. Pursuant to the terms of the plan, overriding royalty interests (“ORRIs”) may be awarded to participants in the plan for prospects in the Gulf of Mexico that are generated or identified and acquired during the term of the participant’s employment at Mariner. The maximum ORRI for all participants is 1.8% for shelf leases and 0.9% for deepwater leases, subject to proportionate reduction. The maximum ORRI per participant is 1/2 of one percent for shelf leases and 1/4 of one percent for deepwater leases, subject to proportionate reduction. Unless approved by Mariner’s overriding royalty interest committee, no ORRIs are awarded for developed or undeveloped reserve acquisitions. Certain of the Forest Gulf of Mexico leases not covering developed or undeveloped reserves may become burdened by ORRIs under the plan as determined by such committee in accordance with the terms of the plan. None of the members of the committee is eligible to participate in the plan.
To avoid potential conflicts of interest, Mariner’s geologist and geophysicist employees that participate in the Overriding Royalty Interest Plan (the “ORRI Plan Participants”) do not make decisions with respect to the pursuit of the acquisition, exploration or development of prospects. When an ORRI Plan Participant develops a lead for a prospect, executive management makes the decision whether to pursue to the acquisition, exploration or development of the prospect. In addition, ORRI Plan Participants are required at the time they become eligible for participation in the plan and periodically thereafter to disclose oil and gas properties in which they or their immediate family members have any interest and to abstain from participation in the evaluation of any property in which they or their immediate family members have any interest.
As of December 31, 2005, six employees participated in the plan. None of Mariner’s officers or managers are eligible to participate in the plan. Since the inception of the plan in July 2002 through December 31, 2005, approximately $584,000 has been distributed to participants with respect to ORRIs granted to them under the plan, of which $332,000 was distributed in 2005.
In 2002, two of our current executive officers, Dalton F. Polasek, Chief Operating Officer, and Judd A. Hansen, Vice President - Shelf and Onshore, received assignments of ORRIs in certain leases acquired by us under a consulting arrangement. A consulting company owned in part by Mr. Polasek was assigned a 2% ORRI from us in four federal offshore leases as partial consideration for having brought the related prospect to us. With our knowledge and consent, the consulting company subsequently assigned portions of the ORRIs to Mr. Hansen and a company owned by Mr. Polasek. At the time of the assignments, Messrs. Polasek and Hansen served Mariner as officers and consultants but were not employed by Mariner. No payments were made in respect of these ORRIs until 2004, when each received less than $60,000 with respect to his ORRI. No payments were made in respect of these ORRIs in 2005.
We may have obligations under previously terminated employment and consulting agreements to assign additional ORRIs in some of our oil and natural gas prospects to current and former employees and consultants. Cory L. Loegering, Vice President - Deepwater, is the only current executive officer who may be entitled to receive ORRIs from time to time under any of these agreements. Mariner made net cash payments to Mr. Loegering of $378,312, $368,095 and $205,245 in 2005, 2004 and 2003, respectively, in respect of ORRIs assigned from time to time pursuant to a right to receive such ORRIs that were granted in 2002.
All ORRIs assigned to these parties are excluded from Mariner’s interests evaluated in our reserve report.
Equity Participation Plan
We adopted an Equity Participation Plan that provided for the one-time grant at the closing of our private equity placement on March 11, 2005 of 2,267,270 restricted shares of our common stock to certain of our employees. No further grants will be made under the Equity Participation Plan, although persons who received such a grant may be eligible for future awards of restricted stock or stock options under our Amended and Restated Stock Incentive Plan described below.
We intended the grants of restricted stock under the Equity Participation Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common stock. Therefore, Equity Participation Plan grantees did not pay any consideration for the common stock they received, and we received no remuneration for the stock.
The table below includes information regarding the restricted stock awards granted in March 2005 under the Equity Participation Plan to our chief executive officer, our four other most highly compensated executive officers as of the year ended 2005, and all officers as a group. Grantees are entitled to vote, and accrue dividends on, the restricted stock prior to vesting; provided, however that any dividends that accrue on the restricted stock prior to vesting will only be paid to grantees to the extent the restricted stock vests.
Equity Participation Plan
Restricted Stock Awards
(1)
Based on a price of $14.00 per share.
Except as described below, the restricted shares will be automatically forfeited in the event a grantee’s employment terminates prior to the vesting date of the awards. The restricted stock granted will vest, and restrictions will terminate, on the later of (i) the first anniversary of the grant date, which was March 11, 2005, and (ii) the occurrence of a “Public Sale Date”; but in no event later than the second anniversary of the date of grant. For purposes of grants under the Equity Participation Plan, “Public Sale Date” means the earlier to occur of:
•
the 90th day following the date on which our common stock is listed on the New York Stock Exchange or admitted to trading and quoted on the Nasdaq National Market or Nasdaq SmallCap Market; and
•
the first date on which both of the following conditions are met: (a) a registration statement covering the resale of the restricted stock has been declared effective by the SEC, and no stop order suspending the effectiveness of such registration statement is in effect and (b) the common stock is listed on the New York Stock Exchange or admitted to trading and quoted on the Nasdaq National Market or Nasdaq SmallCap Market;
provided, however, that if either of the above events occurs and the restricted shares are subject to restrictions on resale as a result of any lock-up agreement or arrangement in connection with a public offering, the Public Sale Date shall be the earlier of the first business day following the date of expiration of the lock-up period and a date 181 days from the date the lock-up period commences.
Notwithstanding the above vesting schedule, the unvested shares of restricted stock will become fully vested upon death or disability of the employee, or if employment is terminated by us for reasons other than for “cause,” or if the employee elects to terminate employment with “good reason,” or upon the occurrence of a “change of control,” as those terms are defined in the agreement with us governing the grant. In connection with the merger with Forest Energy Resources, (i) the 463,656 shares of restricted stock held by non-executive employees vested, and (ii) each of Mariner’s executive officers agreed, in exchange for a cash payment of $1,000, that his or her shares of restricted stock will not vest before the later of March 11, 2006 or ninety days after the effective date of the merger, which is May 31, 2006.
In accordance with GAAP, we expect to incur significant compensation expense as a result of the grants of restricted stock under the Equity Participation Plan. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates - Compensation Expense” for a discussion of these charges.
Stock may be withheld by us upon vesting to satisfy our tax withholding obligations with respect to the vesting of the restricted stock. Participants in the Equity Participation Plan have the right to elect to have us
withhold and cancel shares of the restricted stock to satisfy withholding obligations. In such events, we are required to pay any tax withholding obligation in cash.
The Equity Participation Plan is administered by our Board of Directors. The Board of Directors may delegate administration of the plan to a committee of the Board of Directors. The Equity Participation Plan will expire upon the vesting or forfeiture of all shares granted thereunder. As a result of the merger, we expect all shares of restricted stock granted under the Equity Participation Plan to vest by May 31, 2006.
Amended and Restated Stock Incentive Plan
We adopted a Stock Incentive Plan which became effective March 11, 2005 and was amended and restated on March 2, 2006. The objectives of the Amended and Restated Stock Incentive Plan are to encourage employees and directors to acquire or increase their equity interest with Mariner and to provide a means whereby they may develop a sense of proprietorship and personal involvement in the development and financial success of Mariner. The Amended and Restated Stock Incentive Plan is also designed to enhance Mariner’s ability to attract and retain the services of individuals who are essential for the growth and profitability of Mariner.
Awards to participants under the Amended and Restated Stock Incentive Plan may be made in the form of incentive stock options, or ISOs, non-qualified stock options or restricted stock. The participants to whom awards are granted, the type or types of awards granted to a participant, the number of shares covered by each award, the purchase price, conditions and other terms of each award are determined by the Board of Directors or the committee appointed by the Board of Directors to administer the Amended and Restated Stock Incentive Plan (the “Committee”).
Shares Subject to the Amended and Restated Stock Incentive Plan
A total of 6.5 million shares of Mariner’s common stock is subject to the Amended and Restated Stock Incentive Plan. No more than 2.85 million shares issuable upon exercise of options or as restricted stock can be issued to any individual. As of March 17, 2006, approximately 5.7 million shares remained available under the Amended and Restated Stock Incentive Plan for future issuance to participants.
Administration and Eligibility
The Committee has the authority to administer the Amended and Restated Stock Incentive Plan and to take all actions that are specifically contemplated by the Amended and Restated Stock Incentive Plan or are necessary or appropriate in connection with the administration of the Amended and Restated Stock Incentive Plan. The Committee has the full power and authority to designate participants, determine the type or types of awards, the number of shares to be covered by awards, and the terms and conditions of any award. The Committee also determines whether, to what extent, and under what circumstances awards may be settled or exercised in cash, shares or other securities, other awards or other property, or canceled, forfeited or suspended and the method or methods by which awards may be settled, exercised, canceled, forfeited or suspended. The Committee has the authority to establish, amend, suspend or waive such rules and regulations, and appoint such agents as it shall deem appropriate, and make any other determination or take any other action the Committee deems necessary for the proper administration of the Amended and Restated Stock Incentive Plan.
Any employee of Mariner (or any parent entity or subsidiary) and any non-employee director of Mariner is eligible to be designated a participant by the Committee. As of December 31, 2005, two non-employee directors and 51 employees had been granted awards under the Amended and Restated Stock Incentive Plan.
Awards
Awards may, in the discretion of the Committee, be granted either alone or in addition to, or in tandem with, any other award granted under the Amended and Restated Stock Incentive Plan or any award granted under any other plan of Mariner or any parent entity or subsidiary. Awards granted in addition to or in tandem with other awards or awards granted under any other plan of Mariner or any parent entity or subsidiary may
be granted either at the same time as or at a different time from the grant of such other awards. All or part of an award may be subject to conditions established by the Committee.
The types of awards to participants that may be made under the Amended and Restated Stock Incentive Plan are as follows:
Options. Options are rights to purchase a specified number of shares of common stock at a specified price. The Committee will determine the participants to whom options are granted, the number of shares to be covered by each option, the purchase price and the conditions, which of the options is an ISO or a non-qualified stock option, and limitations applicable to the exercise of the option. To the extent that the aggregate fair market value, determined at the time the respective ISO is granted, of common stock with respect to which ISOs are exercisable for the first time by an individual during any calendar year under all incentive stock option plans of Mariner and its parent and subsidiary corporations exceeds $100,000, or such option fails to constitute an ISO for any reason, such purported ISOs will be treated as non-qualified stock options.
ISOs may be granted only to an individual who is an employee of Mariner or any parent or subsidiary corporation at the time the option is granted. The Committee determines the exercise price at the time each option is granted, but the exercise price shall never be less than the fair market value per share on the effective date of such grant. The Committee determines the time or times at which each option may be exercised, the method or methods by which, and the form or forms in which, payment of the exercise price may be made or deemed to have been made.
An ISO must be granted within 10 years from the date the Amended and Restated Stock Incentive Plan was approved by the Board or the shareholders, whichever is earlier. No ISO shall be granted to an individual if, at the time the ISO is granted, such individual owns stock possessing more than 10% of the total combined voting power of all classes of stock of Mariner or of its parent or subsidiary corporation, unless:
•
at the time the ISO is granted, the option price is at least 110% of the fair market value of the common stock subject to the option; and
•
such ISO, by its terms, is not exercisable after the expiration of five years from the date of grant.
Options are not transferable, other than by will or the laws of descent and distribution, and are exercisable during the participant’s lifetime only by the participant or the participant’s guardian or legal representative.
Restricted Stock. Restricted stock is stock that has limitations placed on it. Dividends paid on restricted stock may be paid directly to the participant, sequestered and held in a bookkeeping account, or reinvested in additional shares, which may be subject to the same restrictions as the underlying award or other restrictions, as determined by the Committee. Restricted stock is evidenced in such manner as deemed appropriate by the Committee, but any stock certificate that is issued in respect of restricted stock granted under the Amended and Restated Stock Incentive Plan must be registered under the participant’s name and bear an appropriate legend referring to the terms, conditions and restrictions applicable to the restricted stock.
Unless otherwise determined by the Committee or provided in an award agreement, upon termination of a participant’s employment for any reason during the applicable restricted period, which is the period established by the Committee with respect to an award during which the award either remains subject to forfeiture or is not transferable by the participant, all restricted stock is forfeited without payment and reacquired by Mariner. The Committee may waive in whole or in part any or all remaining restrictions on such participant’s restricted stock, but if such award was intended to qualify as performance-based compensation, then only upon an event permitted under Section 162(m) of the Code. Restricted stock is subject to such limitations on transfer as are necessary to comply with Section 83 of the Code.
Other Provisions
Unless sooner terminated, no award may be granted under the Amended and Restated Stock Incentive Plan after October 12, 2015. The Board of Directors or the Committee may amend, alter, suspend, discontinue or terminate the Stock Incentive Plan without the consent of any stockholder, participant, other holder or
beneficiary of an award or any other person. However, no amendment may materially adversely affect the rights of a participant under an award without the consent of such participant.
In the event of any distribution, recapitalization, reorganization, merger, spin-off, split-off, split-up, consolidation, combination, repurchase, or exchange of shares or other securities of Mariner or any other relevant corporate transaction or event or any unusual or nonrecurring transactions or events affecting Mariner, the Committee may, in its sole discretion and on such terms and conditions as it deems appropriate:
•
provide for either the termination of any such award in exchange for cash in the amount that would have been attained upon the exercise of such award or the replacement of such award with other rights or property selected by the Committee;
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provide that such award be assumed by the successor or survivor corporation or its parent or be substituted for by similar options, rights or awards; or
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make adjustments in the number and type of shares or other property subject to outstanding awards.
Amended and Restated Stock Incentive Plan Benefits
Because the granting of awards under the Amended and Restated Stock Incentive Plan is at the discretion of the Committee, it is not now possible to determine which persons may be granted awards. Also, it is not now possible to estimate the number of shares of common stock that may be awarded under the Amended and Restated Stock Incentive Plan.
U.S. Federal Tax Consequences
The following is a general discussion of the current Federal income tax consequences of awards under the Amended and Restated Stock Incentive Plan to participants who are classified as U.S. residents for Federal income tax purposes. Different or additional rules may apply to participants who are subject to income tax in a foreign jurisdiction and/or are subject to state or local income tax in the United States. Each participant should rely on his or her own tax advisors regarding federal income tax treatment under the Amended and Restated Stock Incentive Plan.
Restricted Stock
The grant of restricted stock does not result in taxable income to the participant. At each vesting event, the participant will recognize taxable ordinary income equal to the excess of the fair market value of the shares of common stock that become vested over the purchase price (if any) paid for such common stock. However, if a participant makes a timely election under Section 83(b) of the Code, the participant will recognize taxable ordinary income in the taxable year of the grant equal to the excess of the fair market value of the shares of common stock underlying the restricted stock award at the time of the grant over the purchase price (if any) paid for such common stock. Furthermore, the participant will not recognize ordinary income on such restricted stock when it subsequently vests.
In all cases, the participant’s ordinary income is subject to applicable withholding taxes. Mariner will be allowed an income tax deduction in the taxable year the participant recognizes ordinary income, in an amount equal to such ordinary income.
Stock Options
The grant of a non-qualified stock option will not result in taxable income to the participant and Mariner will not be entitled to an income tax deduction. Upon the exercise of a non-qualified stock option, a participant will realize ordinary taxable income on the date of exercise. Such taxable income will equal the difference between the fair market value of the common stock on the date of exercise and the option price. Mariner will be entitled to an income tax deduction equal to the amount included in the participant’s ordinary income.
Upon the grant or exercise of an ISO, a participant will not recognize taxable income and Mariner will not be entitled to an income tax deduction. However, the exercise of an ISO will result in an amount being
included in the participant’s alternative minimum taxable income for the year in which the exercise occurs equal to the excess of the fair market value of the common stock purchased under the ISO at the time of exercise over the option price.
The optionee will recognize taxable income in the year in which the shares of common stock underlying the ISO are sold or disposed of. Dispositions are divided into two categories: qualifying and disqualifying. A qualifying disposition occurs if the sale or disposition is made more than two years from the option grant date and more than one year from the exercise date. If the participant sells or disposes of the shares of common stock in a qualifying disposition, any gain recognized by the participant on such sale or disposition will be a long-term capital gain.
If either of the two holding periods described above are not satisfied, then a disqualifying disposition will occur. If the optionee makes a disqualifying disposition of the shares of common stock that have been acquired through the exercise of the option, then the optionee will have ordinary taxable income for the taxable year in which the sale or disposition occurs equal to the lesser of:
•
the excess of the fair market value of such shares on the option exercise date over the exercise price paid for the shares; or
•
the amount realized on the sale or disposition over the exercise price paid for the shares.
If the optionee makes a qualifying disposition, Mariner will not be entitled to an income tax deduction. However, if the optionee makes a disqualifying disposition, Mariner will be entitled to an income tax deduction equal to the amount included in ordinary income to the participant.
The table below includes information regarding stock options under the Amended and Restated Stock Incentive Plan granted in our last fiscal year to our chief executive officer and our four other most highly compensated executive officers.
Option Grants in Last Fiscal Year
(1)
In accordance with SEC rules, these columns show gain that could accrue for the listed options, assuming that the market price per share of our common stock appreciates from the date of grant over a period of 10 years at an annualized rate of 5% and 10%, respectively. If the stock price does not increase above the exercise price at the time of exercise, the realized value from these options will be zero.
Compensation Committee Interlocks and Insider Participation
None of our executive officers serves as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of our Board of Directors or compensation committee.
During the fiscal year 2005, the Board of Directors determined executive compensation.
Director Compensation
Officers and employees who also serve as directors will not receive additional compensation. For periods before August 11, 2005, Messrs. Aronson and Ginns did not receive compensation for their services as directors. For director services from August 11, 2005 through March 1, 2006, the Company paid cash compensation on an annual basis of $40,000 to each of Messrs. Aronson, Ginns, Greene and Schwager. In addition, on March 31, 2006, the Company will grant each of them 1,100 shares of restricted stock under the Company’s Amended and Restated Stock Incentive Plan, as amended, with one-third of the shares to vest upon each of the first three annual meetings of Mariner’s stockholders following the date of grant. The 1,100 shares of restricted stock being granted to each of Messrs. Greene and Schwager will replace an option each received upon his appointment to the Board in August 2005, exercisable for 4,500 shares of the Company’s common stock, vesting in 1/3 increments upon each of the three successive annual meetings of Mariner’s stockholders following the date of grant, and exercisable for $15.50 per share. As of March 30, 2006, neither of these in-the-money options had been exercised.
Effective March 2, 2006, non-employee directors will receive annual compensation for service as a director of $50,000, and additional annual compensation of $12,500 for serving on the board’s audit committee, $20,000 for serving as chairman of the audit committee, $5,000 for serving on any board committee other than the audit committee, and $10,000 for serving as chairman of any board committee other than the audit committee. Non-employee directors also will be paid a meeting fee of $1,500 and $1,000 for attendance or participation by phone at board meetings and board committee meetings, respectively. All non-employee director fees will be paid quarterly. In addition, each director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the Board of Directors or committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.
The Board of Directors has authorized a restricted stock grant that will be made on March 31, 2006 to each non-employee director equal to that number of shares of Mariner’s common stock with a market value, determined as of the date of grant, of $50,000, with one-third of the shares to vest on each of the first three annual meetings of Mariner’s stockholders following the date of grant. The grants will be made under Mariner’s Amended and Restated Stock Incentive Plan, as amended.
Indemnification
We maintain directors’ and officers’ liability insurance. Our certificate of incorporation and bylaws include provisions limiting the liability of directors and officers and indemnifying them under certain circumstances. We have also entered into indemnification agreements with our executive officers and directors providing our executive officers and directors with additional assurances in a manner consistent with Delaware law.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth information as of March 17, 2006 with respect to the beneficial ownership of Mariner’s common stock by (i) 5% stockholders, (ii) current directors, (iii) five most highly compensated executive officers during 2005 and (iv) executive officers and directors as a group.
Unless otherwise indicated in the footnotes to this table, each of the stockholders named in this table has sole voting and investment power with respect to the shares indicated as beneficially owned.
*
Less than 1%.
(1)
As a result of the merger with Forest Energy Resources on March 2, 2006, Mariner issued 50,637,010 shares of its common stock to former Forest Energy Resources shareholders. As of March 17, 2006, Mariner had 86,100,994 shares of common stock issued and outstanding. As of that date, the only stockholder of record holding more than 5% of Mariner’s issued and outstanding common stock was CEDE & CO (FAST) which held of record 79,350,067 or 92.2% of such shares. Mariner understands that CEDE & CO (FAST) does not beneficially own such shares and as of March 17, 2006, had not been able to ascertain whether any of the beneficial owners of such shares owned more than 5% of Mariner’s issued and outstanding common stock except as indicated in footnotes (3) and (4) below. CEDE & CO (FAST)’s address is PO Box 20, Bowling Green Station, New York, NY 10004.
(2)
Includes grants of restricted stock to executive officers under our Equity Participation Plan. These shares may be voted, but not disposed of, prior to vesting. Also includes shares issuable upon exercise of presently exercisable options held by certain of the indicated persons.
(3)
Of the amount shown, 1,536,083 shares are held by Fidelity Contrafund, 2,081,700 shares are held by Fidelity Puritan Trust: Fidelity Low-Priced Stock Fund, 438,717 shares are held by Variable Insurance Products Fund II: Contrafund Portfolio, 516,300 shares are held by Fidelity Puritan Trust: Fidelity Balanced Fund, 200,000 shares are held by Fidelity Securities Fund: Fidelity Small Cap Value Fund, 75,000 shares are held by Fidelity Commonwealth Trust: Fidelity Small Cap Retirement Fund, and 4,400 shares are held by Fidelity Management Trust Company on behalf of accounts managed by it. Fidelity may be deemed a beneficial owner of these shares by virtue of its affiliation with these holders.
(4)
On March 17, 2006, Fidelity Investments advised Mariner that in addition to the amount shown, Fidelity received shares of Mariner in connection with the merger with Forest Energy Resources. As of March 17, 2006, Mariner was unable to ascertain the number of such additional Mariner shares.
(5)
The address of each officer and director is c/o Mariner Energy, Inc., One BriarLake Plaza, Suite 2000, 2000 West Sam Houston Parkway South, Houston, Texas 77042.
(6)
Includes 66,667 shares issuable upon exercise of a presently exercisable option.
(7)
Includes 34,000 shares issuable upon exercise of a presently exercisable option.
(8)
Includes 24,667 shares issuable upon exercise of a presently exercisable option.
(9)
Includes 13,334 shares issuable upon exercise of a presently exercisable option.
(10)
Mr. Aronson indirectly owns 1,213 shares that are directly owned by the Bolivar International Defined Benefit Pension Plan and 404 shares that are directly owned by his IRA. Mr. Aronson may be deemed to be a beneficial owner of 1,895,630 shares and 1,509,577 shares that are beneficially owned by ACON E&P, LLC and ACON Investments LLC, respectively. MEI Acquisitions Holdings, LLC is the record holder of the shares beneficially owned by ACON E&P, LLC. MEI Investment Holdings, LLC is the holder of the shares beneficially owned by ACON Investments LLC. Mr. Aronson is a manager of ACON E&P, LLC and a managing member of ACON Investments LLC, the managing member of MEI Investment Holdings, LLC. Mr. Aronson disclaims beneficial ownership of these shares except to the extent of his pecuniary interest therein. Mr. Aronson’s address is c/o ACON Investments, LLC, 1133 Connecticut Avenue, N.W., Suite 700, Washington, D.C. 20036.
(11)
Mr. Ginns may be deemed to be a beneficial owner of 1,895,630 shares and 1,509,577 shares that are beneficially owned by ACON E&P, LLC and ACON Investments LLC, respectively. MEI Acquisitions Holdings, LLC is the record holder of the shares beneficially owned by ACON E&P LLC. MEI Investment Holdings, LLC is the holder of the shares beneficially owned by ACON Investments LLC. Mr. Ginns is a managing member of Burns Park Investments LLC, a manager of ACON E&P, LLC. Mr. Ginns is a managing member of ACON Investments LLC, the managing member of MEI Investment Holdings, LLC. Mr. Ginns disclaims beneficial ownership of these shares except to the extent of his pecuniary interest therein. Mr. Ginn’s address is c/o ACON Investments, LLC, 1133 Connecticut Avenue, N.W., Suite 700, Washington, D.C. 20036.
(12)
Includes 1,500 shares issuable upon exercise of a presently exercisable option.
(13)
Includes 197,670 shares issuable upon exercise of presently exercisable options.
Equity Compensation Plan Information
The following table summarizes information about our equity compensation plans as of December 31, 2005.
(1)
These plans consist of our Equity Participation Plan and our Stock Incentive Plan.
(2)
Includes 2,267,270 restricted shares of our common stock and outstanding options to
purchase 809,000 shares of our common stock issued as of December 31, 2005.
(3)
Includes 1,191,000 shares of our common stock available for issuance under the Stock Incentive Plan as of December 31, 2005. In the first quarter of 2006, we amended and restated the Stock Incentive Plan to add an additional 4.5 million shares of common stock to the plan.
Item 13.
Item 13.
Certain Relationships and Related Transactions.
In connection with Mariner’s merger in March 2004, Mariner Energy LLC, our former indirect parent, entered into management agreements with each of Carlyle/Riverstone Energy Partners II, L.P. (“C/R Energy Partners”) and ACON E&P III, LLC (“ACON E&P”), pursuant to which C/R Energy Partners and ACON E&P received aggregate fees in the amount of $2.5 million. C/R Energy Partners was, and ACON E&P is, an affiliate of MEI Acquisitions Holdings, LLC, our former sole stockholder. No additional fees are payable under these agreements.
Under a C/R Monitoring Agreement with C/R Energy Partners and under an ACON Monitoring Agreement with ACON E&P, each dated as of March 2, 2004, we were obligated to pay monitoring fees in the aggregate amount of 1% of our annual consolidated EBITDA to C/R Energy Partners and ACON E&P payable on a calendar quarter basis. Under the terms of the monitoring agreements, the affiliates provided financial advisory services in connection with the ongoing operations of Mariner subsequent to the merger. We accrued $1.4 million in monitoring fees under these agreements for 2004. The parties terminated these agreements on February 7, 2005 in return for lump sum cash payments by Mariner totalling $2.3 million. We intend to engage in transactions with our affiliates in the future only when the terms of any such transactions are no less favorable than transactions that could be obtained from third parties.
We used $166 million of the net proceeds from our sale of 12,750,000 shares of common stock in our 2005 private placement to purchase and retire an equal number of shares of our common stock shares then held by MEI Acquisitions Holdings, LLC, our former sole stockholder.
The estimated $1.9 million in expenses related to the March 2005 private placement included approximately $0.8 million of expenses incurred by our former sole stockholder, MEI Acquisitions Holdings, LLC, and its members in connection with the offering.
We currently have obligations concerning ORRI arrangements with two of our officers who received assignments of ORRIs in certain leases acquired by us under a consulting agreement and with another officer who may be entitled to assignments of ORRIs under a previously terminated employment agreement, as described in Item 11, “Executive Compensation-Overriding Royalty Arrangements.”
Item 14.
Item 14.
Principal Accounting Fees and Services.
Deloitte & Touche LLP served as our independent registered public accountants for fiscal year 2005. A representative of Deloitte & Touche LLP is expected to attend our next annual meeting and will have the opportunity to make a statement if he or she so desires and will be available to answer appropriate stockholder questions.
Audit Fees. We incurred fees of $935,230 during fiscal 2005 and $580,085 during fiscal 2004 for Deloitte & Touche LLP’s independent audit of our annual financial statements and assistance regarding other SEC filings.
Audit-Related Fees. None.
Tax Fees. We incurred no tax fees in fiscal 2005 and incurred $33,000 in tax fees in fiscal 2004.
All Other Fees. None.
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules.
(a)(1) Financial Statements:
The financial statements included in Item 8 above are filed as part of this Annual Report.
(a)(2) Financial Statement Schedules:
None.
(a)(3) and (b) Exhibits:
The exhibits listed on the Exhibit Index which follows the Signatures hereto are filed as part of this annual report.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Mariner Energy, Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 30, 2006.
Mariner Energy, Inc.
By: /s/ Scott D. Josey
Name: Scott D. Josey
Title:
Chairman of the Board, Chief Executive
Officer and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of Mariner Energy, Inc. in the capacities indicated as of March 30, 2006:
INDEX TO EXHIBITS
*
Incorporated by reference as indicated
In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.

Management contracts or compensatory plans or arrangements.