Item 1A. Risk Factors
The nature of the business activities conducted by Swift Energy subjects it to certain hazards and risks. The following is a summary of all the material risks relating to our business activities.
Oil and natural gas prices are volatile. A substantial decrease in oil and natural gas prices would adversely affect our financial results.
Our future revenues, net income, cash flow, and the value of our oil and natural gas properties depend primarily upon market prices for oil and natural gas. Oil and natural gas prices historically have been volatile and will likely continue to be volatile in the future. The recent oil and natural gas prices may not continue and could drop precipitously in a short period of time. The prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, worldwide economic conditions, weather conditions, currency exchange rates, and political conditions in major oil producing regions, especially the Middle East. A significant decrease in price levels for an extended period would negatively affect us in several ways:
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our cash flow would be reduced, decreasing funds available for capital expenditures employed to increase production or replace reserves;
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certain reserves would no longer be economic to produce, leading to both lower cash flow and proved reserves;
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our lenders could reduce the borrowing base under our bank credit facility because of lower oil and natural gas reserves values, reducing our liquidity and possibly requiring mandatory loan repayments; and
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access to other sources of capital, such as equity or long term debt markets, could be severely limited or unavailable in a low price environment.
Consequently, our revenues and profitability would suffer.
Enactment of Congressional and regulatory proposals under consideration could negatively affect our business.
Numerous legislative and regulatory proposals affecting the oil and gas industry have been proposed or are under consideration by the Obama administration, Congress and various federal agencies. Among these proposals are: (1) climate change legislation introduced in Congress, Environmental Protection Agency regulations, carbon emission "cap-and-trade" regimens, and related proposals, none of which have been have been adopted in final form; (2) proposals contained in the President's budget, along with legislation introduced in Congress, none of which have been enacted by both houses of Congress, to repeal various tax deductions or exemptions available to oil and gas producers, such as the tax deduction for intangible drilling and development costs, which if eliminated could raise the cost of energy production, reduce energy investment and affect the economics of oil and gas exploration and production activities; and (3)legislation being considered by Congress that would subject the process of hydraulic fracturing to federal regulation under the Safe Drinking Water Act, which could affect Company operations, their effectiveness, and the costs thereof. Any such future laws and regulations could result in increased costs or additional operating restrictions, and could have an effect on demand for oil and gas or prices at which it can be sold. Until any such legislation or regulations are enacted or adopted, it is not possible to gauge their impact on our future operations or our results of operations and financial condition.
Estimates of proved reserves are uncertain, and revenues from production may vary significantly from expectations.
The quantities and values of our proved reserves included in this report are only estimates and subject to numerous uncertainties. Estimates by other engineers might differ materially. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation. These estimates depend on assumptions regarding quantities and production rates of recoverable oil and natural gas reserves, future prices for oil and natural gas, timing and amounts of development expenditures and operating expenses, all of which will vary from those assumed in our estimates. These variances may be significant.
Any significant variance from the assumptions used could result in the actual amounts of oil and natural gas ultimately recovered and future net cash flows being materially different from the estimates in our reserves reports. In addition, results of drilling, testing, production, and changes in prices after the date of the estimates of our reserves may result in substantial downward revisions. These estimates may not accurately predict the present value of net cash flows from our oil and natural gas reserves.
At December 31, 2010, approximately 55% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. The reserves data assumes that we can and will make these expenditures and conduct these operations successfully, which may not occur.
Our South Louisiana and Southeast Louisiana core areas remain subject to damage from hurricane activity in the Gulf of Mexico, which could cause a pipeline outage or cause us to suffer significant losses.
Approximately 27% of our 2010 reserves and 52% of our 2010 production are located in our South Louisiana and Southeast Louisiana core areas. Hurricane activity in 2007 and 2008 resulted in production curtailments and physical damage to our Gulf Coast operations. For example, a significant percentage of our production was shut down by Hurricanes Katrina and Rita in 2005, and by Hurricanes Gustav and Ike in 2008. Due to increased costs after the 2005 hurricanes, we no longer carry business interruption insurance. If hurricanes damage the Gulf Coast region where we have a significant percentage of our operations, our cash flow would suffer. This decrease in cash flow, depending on the extent of the decrease, could reduce the funds we would have available for capital expenditures and reduce our ability to borrow money or raise additional capital.
The continuing pressure on the global credit and financial markets could materially and adversely impact our financial results.
As extensively reported, global credit and financial markets experienced extreme disruptions beginning in the second half of 2008, severely diminishing liquidity and credit availability, volatility in consumer confidence, declines in economic growth, increases in unemployment rates, and uncertainty about economic stability. We cannot assure you that there will not be further deterioration in credit, financial, or commodities markets. These economic conditions have led to higher volatility for crude oil and natural gas prices, as demonstrated by the decline in commodity prices which occurred during the later part of 2008 and into 2009. Our profitability will be significantly affected by decreased demand and lower commodity prices. Our future access to capital and the availability of future financing could be limited due to tightening credit markets that could affect our ability to fund our capital projects.
Our operating results may be adversely affected if economic conditions impact the financial viability of our insurers, oil and gas purchasers, suppliers and commodity derivatives counterparties.
Global economic conditions may adversely affect the financial viability of and increase the credit risk associated with our purchasers, suppliers, insurers, and commodity derivative counterparties to perform under the terms of contracts or financial arrangements we have with them. Although we have heightened our level of scrutiny of our contractual counterparties, our assessment of the risk of non-performance by various parties is subject to sudden swings in the financial and credit markets. This same crisis may adversely impact insurers and their ability to pay current and future insurance claims that we may have.
Negative credit market conditions may adversely affect our access to capital, our liquidity and ability to refinance our debt.
Our future access to capital could be limited due to tightening credit markets that could affect our ability to fund our future capital projects. Negative credit market conditions could materially affect our liquidity and may inhibit our lenders from fully funding our line of credit or cause them to make the terms of our line of credit costlier or more restrictive. We are subject to semi-annual reviews of our borrowing base and commitment amount under our line of credit, and do not know the result of future redeterminations or the effect of then current oil and gas prices on that process. Additionally, our line of credit matures in October 2015, and although it has a zero balance as of December 31, 2010, long-term restriction or freezing of the capital markets may affect the availability or pricing of our renewal of the line of credit.
We have previously incurred a write-down of the carrying values of our properties and could incur additional write-downs in the future.
The SEC accounting rules require that on a quarterly basis we review the carrying value of our oil and natural gas properties for possible write-down or impairment. Starting with our financial statements ending December 31, 2009 the unescalated prices are calculated under the rules using a twelve month rolling average price from the first business day of each month. Any capital costs in excess of the ceiling must be permanently written down. Low oil and gas prices at December 31, 2008 and March 31, 2009 led to $473.1 and $50.0 million non-cash after-tax write-downs of our oil and gas properties, respectively. If oil and gas prices decline in the future, to the degree such that we incur additional capital costs on oil and gas properties and add proved reserves, we may be required to record further write-downs of our oil and gas properties in subsequent periods.
Our oil and natural gas exploration and production business involves high risks and we may suffer uninsured losses.
These risks include blowouts, explosions, adverse weather effects and pollution and other environmental damage, any of which could result in substantial losses to the Company due to injury or loss of life, damage to or destruction of wells, production facilities or other property, clean-up responsibilities, regulatory investigations and penalties and suspension of operations. Although the Company currently maintains insurance coverage that it considers reasonable and that is similar to that maintained by comparable companies in the oil and gas industry, it is not fully insured against certain of these risks, such as business interruption, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining such insurance.
Our level of debt could reduce our financial flexibility.
As of December 31, 2010, our total debt comprised approximately 35% of our total capitalization. Although our bank credit facility and indentures limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness, we will be permitted to incur significant additional indebtedness, including secured indebtedness, in the future if specified conditions are satisfied. Higher levels of indebtedness could negatively affect us by requiring us to dedicate a substantial portion of our cash flow to the payment of interest, and limiting our ability to obtain financing or raise equity capital in the future.
If we cannot replace our reserves, our revenues and financial condition will suffer.
Unless we successfully replace our reserves, our long-term production will decline, which could result in lower revenues and cash flow. When oil and natural gas prices decrease, our cash flow decreases, resulting in less available cash to drill and replace our reserves and an increased need to draw on our bank credit facility. Even if we have the capital to drill, unsuccessful wells can hurt our efforts to replace reserves. Additionally, lower oil and natural gas prices can have the effect of lowering our reserves estimates and the number of economically viable prospects that we have to drill.
Drilling wells is speculative and capital intensive.
Developing and exploring properties for oil and natural gas requires significant capital expenditures and involves a high degree of financial risk, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The budgeted costs of drilling, completing, and operating wells are often exceeded and can increase significantly when drilling costs rise. Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, and mechanical difficulties. Moreover, the successful drilling or completion of an oil or natural gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition, or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
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Hurricanes, tropical storms or other natural disasters;
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environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas, or other pollution into the environment, including groundwater and shoreline contaminate
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abnormally pressured formations;
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mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
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fires and explosions;
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personal injuries and death; and
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented, as is the case in our declining business interruption insurance following the hurricanes in 2005. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect our financial condition.
Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.
To finance acquisitions, we may need to substantially alter or increase our capitalization through the use of our bank credit facility, the issuance of debt or equity securities, the sale of production payments, or by other means. These changes in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or other transactions can change the character of our operations and business. The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. Furthermore, we may not be able to obtain external funding for any such acquisitions or other transactions or to obtain external funding on terms acceptable to us.
Reserves on acquired properties may not meet our expectations, and we may be unable to identify liabilities associated with acquired properties or obtain protection from sellers against associated liabilities.
Property acquisition decisions are based on various assumptions and subjective judgments that are speculative. Although available geological and geophysical information can provide information about the potential of a property, it is impossible to predict accurately a property’s production and profitability. In addition, we may have difficulty integrating future acquisitions into our operations, and they may not achieve our desired profitability objectives. Likewise, as is customary in the industry, we generally acquire oil and natural gas acreage without any warranty of title except through the transferor. In many instances, title opinions are not obtained if, in our judgment, it would be uneconomical or impractical to do so. Losses may result from title defects or from defects in the assignment of leasehold rights. While our current operations are primarily in Louisiana and Texas, we may pursue acquisitions of properties located in other geographic areas, which would decrease our geographical concentration, and could also be in areas in which we have no or limited experience.
In addition, our assessment of acquired properties may not reveal all existing or potential problems or liabilities, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. In the course of our due diligence, we may not inspect every well, platform, or pipeline. Inspections may not reveal structural and environmental problems, such as pipeline corrosion or groundwater contamination. We may not be able to obtain contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of acquired properties in addition to the risk that the properties may not perform in accordance with our expectations.
Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.
There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities, if at all, to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects, or producing fields will be applicable to our drilling prospects. In addition, a variety of factors, including geological and market-related, can cause a well to become uneconomical or only marginally economical. For example, if oil and natural gas prices are much lower after we complete a well than when we identified it as a prospect, the completed well may not yield commercially viable quantities.
In many instances, title opinions on our oil and gas acreage are not obtained if in our judgment it would be uneconomical or impractical to do so.
As is customary in the industry, we generally acquire oil and natural gas acreage without any warranty of title except as to claims made by, through, or under the transferor. Although we have title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights.
Our use of oil and natural gas price hedging contracts involves credit risk and may limit future revenues from price increases and expose us to risk of financial loss.
We enter into hedging transactions for our oil and natural gas production to reduce exposure to fluctuations in the price of oil and natural gas, primarily to protect against declines in prices, although we typically enter into only short-term hedges covering less than 50% of our anticipated production, which limits the price protection they provide. Our hedges at year-end 2010 consisted of natural gas price floors with strike prices ranging between $3.77 and $4.30. Our hedging transactions have also historically consisted of financially settled crude oil and natural gas forward sales contracts with major financial institutions as well as crude oil price floors. We intend to continue to enter into these types of hedging transactions in the foreseeable future when appropriate. Hedging transactions expose us to risk of financial loss in some circumstances, including if production is less than expected, the other party to the contract defaults on its obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. Hedging transactions other than floors may limit the benefit we would have otherwise received from increases in the price for oil and natural gas. Additionally, hedging transactions other than floors may expose us to cash margin requirements.
We may have difficulty competing for oil and gas properties, equipment, supplies, oilfield services, and trained and experienced personnel.
We operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and natural gas properties, as well as for the equipment, labor, and materials required to develop and operate such properties. Many of these competitors have financial and technological resources substantially greater than ours. The market for oil and natural gas properties is highly competitive and we may lack technological information or expertise available to other bidders. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. As demand increases for equipment, services, and personnel, we may experience increased costs and various shortages and may not be able to obtain the necessary oilfield services and trained personnel.
Our business depends on oil and natural gas transportation facilities, some of which are owned by others.
The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of pipeline systems owned by third parties. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.
Governmental laws and regulations are costly and stringent, especially those relating to environmental protection.
Our exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. These laws and regulations affect the costs, manner, and feasibility of our operations and require us to make significant expenditures in our efforts to comply. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and the issuance of injunctions that could limit or prohibit our operations. In addition, some of these laws and regulations may impose joint and several, strict liability for contamination resulting from spills, discharges, and releases of substances, including petroleum hydrocarbons and other wastes, without regard to fault or the legality of the original conduct. Under such laws and regulations, we could be required to remove or remediate previously disposed substances and property contamination, including wastes disposed or released by prior owners or operations. Changes in or additions to environmental laws and regulations occur frequently, and any changes or additions that result in more stringent and costly waste handling, storage, transport, disposal, or cleanup requirements could have a material adverse effect on our operations and financial position.
Climate change legislation and regulatory initiatives could result in increased compliance costs and reduced demand for the oil and natural gas we produce.
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” or “GHGs,” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climatic changes. In December 2009, the EPA issued an “endangerment and cause or contribute finding” for greenhouse gases under section 202(a) of the Clean Air Act, which will allow the EPA to adopt rules under the CAA that directly regulate greenhouse gases. Accordingly, the EPA has adopted regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, in October 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010 and, most recently, on November 8, 2010, adopted amendments to this rule expanding the existing greenhouse gas monitoring and reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmissions, storage and distribution facilities, beginning in 2012 for emissions occurring in 2011.
In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, primarily through means of a cap and trade program that would require either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall greenhouse gas emission reduction goal is achieved. More than one-third of the states (but not currently including Louisiana or Texas) either individually or through multi-state initiatives already have begun implementing legal measures to reduce or report upon emissions of greenhouse gases. Any adoption of legislation or new regulations imposing reporting obligations upon, or limiting emissions of greenhouse gases from, our equipment and operations could adversely impact our business, result in increased compliance costs or additional operating restrictions, and have an adverse effect on demand for the oil and natural gas we produce.
Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Legislation introduced in Congress last year called the “Fracturing Responsibility and Awareness of Chemicals Act,” or “FRAC Act,” would repeal an exemption in the federal Safe Drinking Water Act (“SWDA”) for the underground injection of hydraulic fracturing fluids near drinking water sources. Hydraulic fracturing is an important and commonly used process for the completion of natural gas, and to a lesser extent, oil wells in shale formations, and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate natural gas production. If enacted, the FRAC Act could result in additional regulatory burdens such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements. The FRAC Act also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities, who would then make such information publicly available and make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. The EPA also has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health. In addition, various state and local governments are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure of chemicals used in the fracturing process, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. The adoption of the FRAC Act or any other federal or state laws or regulations imposing disclosure obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas wells in shale formations, increase our costs of compliance, cause delays in permitting, and adversely affect our business.
Recent attention to the use of diesel fuel in hydraulic fracturing could intensify EPA regulation under the Safe Drinking Water Act.
The Safe Drinking Water Act, as amended, currently excludes hydraulic fracturing from EPA regulation so long as no diesel fuel is used in the fracturing process. Recent Congressional investigations have shown that despite the absence of permits being issued for diesel fuel use in fracturing, a number of companies have acknowledged incorporating diesel fuel into their fracturing fluids. Should the EPA decide that companies using diesel fuel in fracturing operations are in violation of the Safe Drinking Water Act, penalties could be imposed on those companies, possibly retroactive in nature. Enhanced EPA regulation of fracturing could impose additional costs on the operations of the Company, alter the effectiveness of fracturing as currently conducted, and alter development plans using the fracturing process. The vendors which the Company contracts with do not currently use diesel fuel in their fracturing fluids.
Environmental Regulations
Our exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit by operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas, wetlands, and other ecologically sensitive and protected areas, and impose substantial remedial liabilities for pollution resulting from drilling operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of significant investigatory or remedial obligations, and the imposition of injunctive relief that limits or prohibits our operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. While we believe that we are in substantial compliance with current environmental laws and regulations and have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future.
We currently own or lease, and have in the past owned or leased, numerous properties in connection with our operations that have been used for the exploration and production of oil and natural gas for many years. Although we have used operation and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or other wastes may have been disposed or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon or away from could be subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault or the legality of the original conduct, including the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as “CERCLA” or the “Superfund” law, the federal Resource Conservation and Recovery Act or “RCRA,” the federal Clean Water Act, the federal Clean Air Act, the federal Oil Pollution Act or “OPA,” and analogous state laws. Under such laws and any implementing regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damages allegedly caused by the release of petroleum hydrocarbons or other wastes into the environment.
Our operations in Louisiana state waters are subject to OPA, which imposes a variety of requirements related to the prevention of oil spills, and liability for damages resulting from such spills in United States waters. The OPA imposes strict, joint and several liability on responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. Liability limits for water based facilities in Louisiana require a responsible party to pay all removal costs, plus up to $75 million in other damages. These liability limits do not apply, however, if the spill was caused by gross negligence or willful misconduct of the party, if the spill resulted from violation of a federal safety, construction or operation regulation, or if the party fails to report the spill or cooperate fully in any resulting cleanup. The OPA also requires a responsible party to submit proof of its financial ability to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. We believe our operations are in substantial compliance with OPA requirements.
United States Federal and State Regulation of Oil and Natural Gas
The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the federal government and are affected by the availability, terms and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The Federal Energy Regulatory Commission (“FERC”) is continually proposing and implementing new rules and regulations affecting the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. Some recent FERC proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.
Our sales of crude oil, condensate and NGLs are not currently subject to FERC regulation. However, the ability to transport and sell such products is dependent on certain pipelines whose rates, terms and conditions of service are subject to FERC regulation.
Since December 2007, Congress has passed the Energy Independence and Security Act of 2007, the Energy Economic Stabilization Act of 2008, and the American Recovery and Reinvestment Act of 2009, each of which contains various provisions affecting the oil and gas industry and related tax provisions. In future periods, Congress may decide to revisit legislation introduced in prior sessions to repeal existing incentives or impose new taxes on the exploration and production of oil and natural gas, and/or create new incentives for alternative energy sources. If enacted, such legislation could reduce the demand for and uses of oil, natural gas and other minerals and/or increase the costs incurred by the Company in its exploration and production activities, which could affect the Company’s revenues, costs, and profits.
Production of any oil and natural gas by us will be affected to some degree by state regulations. Many states in which we operate have statutory provisions regulating the production and sale of oil and natural gas, including provisions regarding deliverability. Such statutes, and the regulations promulgated in connection therewith, are generally intended to prevent waste of oil and natural gas and to protect correlative rights to produce oil and natural gas between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and natural gas produced by assigning allowable rates of production to each well or proration unit, which could restrict the rate of production below the rate that a well would otherwise produce in the absence of such regulation. In addition, certain state regulatory authorities can limit the number of wells or the locations where wells may be drilled. Any of these actions could negatively affect the amount or timing of revenues.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Glossary of Abbreviations and Terms
The following abbreviations and terms have the indicated meanings when used in this report:
ASC - Accounting Standards Codification.
Bbl - Barrel or barrels of oil.
Bcf - Billion cubic feet of natural gas.
Bcfe - Billion cubic feet of natural gas equivalent (see Mcfe).
Boe - Barrels of oil equivalent.
Condensate - Liquid hydrocarbons that are found in natural gas wells and condense when brought to the well surface. Condensate is used synonymously with oil.
Developed Oil and Gas Reserves - Oil and natural gas reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods. 1
Development Well - A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Discovery Cost - With respect to proved reserves, a three-year average (unless otherwise indicated) calculated by dividing total incurred exploration and development costs (exclusive of future development costs) by net reserves added during the period through extensions, discoveries, and other additions.
Dry Well - An exploratory or development well that is not a producing well.
EBITDA - Earnings before interest, taxes, depreciation, depletion and amortization.
EBITDAX - Earnings before interest, taxes, depreciation, depletion and amortization, and exploration expenses. Since Swift Energy uses full-cost accounting for oil and property expenditures, as noted in footnote one of the accompanying consolidated financial statements, exploration expenses are not applicable to Swift Energy.
Exploratory Well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. 2
FASB - The Financial Accounting Standards Board.
Gross Acre - An acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
Gross Well - A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.
MBbl - Thousand barrels of oil.
MBoe - Thousand barrels of oil equivalent.
Mcf - Thousand cubic feet of natural gas.
Mcfe - Thousand cubic feet of natural gas equivalent, which is determined using the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf of natural gas.
MMBbl - Million barrels of oil.
MMBoe - Million barrels of oil equivalent.
MMBtu - Million British thermal units, which is a heating equivalent measure for natural gas and is an alternate measure of natural gas reserves, as opposed to Mcf, which is strictly a measure of natural gas volumes. Typically, prices quoted for natural gas are designated as price per MMBtu, the same basis on which natural gas is contracted for sale.
MMcf - Million cubic feet of natural gas.
MMcfe - Million cubic feet of natural gas equivalent (see Mcfe).
Net Acre - A net acre is deemed to exist when the sum of fractional working interests owned in gross acres equals one. The number of net acres is the sum of fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
Net Well - A net well is deemed to exist when the sum of fractional working interests owned in gross wells equals one. The number of net wells is the sum of fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.
NGL - Natural gas liquid.
Producing Well - An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Proved Oil and Gas Reserves - Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. For reserves calculations on or after December 31, 2009, economic conditions include prices based on either the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. 3
Proved Undeveloped (PUD) Locations - A location containing proved undeveloped reserves.
PV-10 Value - The estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. These amounts are calculated net of estimated production costs and future development costs, using prices based on either the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements, without escalation and without giving effect to non-property related expenses, such as general and administrative expenses, debt service, future income tax expense, or depreciation, depletion, and amortization. PV-10 Value is a non-GAAP measure and its use is explained under “Item 2.
Item 3. Legal Proceedings
No material legal proceedings are pending other than ordinary, routine litigation and claims incidental to our business. We have further discussed our New Zealand litigation in footnote 8 of the notes to consolidated financial statements (“Discontinued Operations”)
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted during the fourth quarter of 2010 to a vote of security holders.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock, 2009 and 2010
Our common stock is traded on the New York Stock Exchange under the symbol “SFY.” The high and low quarterly closing sales prices for the common stock for 2009 and 2010 were as follows:
Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our credit agreements, as discussed in Note 4 to the consolidated financial statements, and we presently intend to continue a policy of using retained earnings for expansion of our business.
We had approximately 183 stockholders of record as of December 31, 2010.
Stock Repurchase Table
The following table summarizes repurchases of our common stock occurring during the fourth quarter of 2010:
Equity Compensation Plan Information
The table summarizing information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2010 is located in Note 6 of Notes to Consolidated Financial Statements.
Share Performance Graph
The following Share Performance Graph shall not be deemed to be “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.
Item 6.
Item 6. Selected Financial Data
(1) Amounts have been retroactively adjusted in all periods presented to give recognition to: (a) discontinued operations related to the sale of our New Zealand oil & gas assets, and (b) the conversion of production and reserves volumes to a Boe basis.
(2) These prices do not include the effects of our hedging activities which were recorded in “Price-risk management and other, net” on the accompanying statements of operations. The hedge adjusted prices are detailed in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this Form 10-K. Natural gas sales prices represents the amount realized per MCF of production.
Item 7.
Item 7. Management’s Discussion and Analysis of
Financial Condition and Results of Operations
You should read the following discussion and analysis in conjunction with our financial information and our audited consolidated financial statements and accompanying notes for the years ended December 31, 2009, 2008, and 2007 included with this report. Unless otherwise noted, both historical information for all periods and forward-looking information provided in this Management’s Discussion and Analysis relates solely to our continuing operations located in the United States, and excludes our New Zealand discontinued operations. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 39 of this report.
Overview
We are an independent oil and natural gas company formed in 1979, and we are engaged in the exploration, development, acquisition and operation of oil and natural gas properties, with a focus on our reserves and production from our Texas properties as well as onshore and inland waters of Louisiana. We are one of the largest producers of crude oil in the state of Louisiana, and hold a large acreage position in Texas prospective for liquids-rich Eagle Ford shale and Olmos tight sands development. Oil production accounted for 47% of our 2010 production and 71% of our oil and gas revenues, and combined production for both oil and natural gas liquids (“NGLs”) made up 61% of our 2010 production and 82% of our oil and gas sales. This emphasis has allowed us to benefit from better margins for oil production than natural gas production during 2010.
2010 Highlights
Increases in Earnings and Cash Flow. Our year-to-year income from continuing operations increased by $85.6 million and cash provided by operating activities increased by $32.8 million, as oil and NGL prices received in 2010 were 32% and 35% higher, respectively, than the average prices we received in 2009, while natural gas prices increased 14% in 2010.
Improved Liquidity at Year-End 2010. In November 2010, we raised $140.1 million net through an underwritten public stock offering of 4.0 million shares of our common stock at a price of $36.60 per share. This followed an equity offering in the third quarter of 2009 when we raised $108.8 million net in the sale of 6.21 million shares of our common stock at a price of $18.50 per share. Taken together with $300.0 million of borrowing capacity under our credit agreement at December 31, 2010, our improved liquidity provides capital, if needed, for our expanded 2011 drilling program.
Increased Reserves. Year-end 2010 total proved reserves increased 18%, or 19.9 MMBoe over reserves quantities at December 31, 2009, with a year-end 2010 PV-10 value increasing by approximately $450 million to $1.8 billion.
South Texas Drilling. During 2010 we drilled 32 horizontal wells and an additional 6 vertical wells helping us evaluate Eagle Ford and Olmos acreage positions in our South Texas area. At year-end, our South Texas core area surpassed Southeast Louisiana in terms of both production and proven reserves. We also entered into long-term agreement with a major industry service provider for South Texas, securing access to fracing services at competitive prices for a two-year period.
Shareholder Return. We had annual shareholder return during 2010 of 63%.
Development Joint Ventures. Over the last 15 months we have entered into joint venture agreements with large independent oil and gas producers covering acreage in both our AWP and Burr Ferry fields, allowing us to both monetize a portion of our significant acreage positions (including a 26,000 acre portion of our Eagle Ford Shale acreage in McMullen County, Texas) and share costs of development drilling in these fields in order to accelerate their development.
2011 Objectives
In 2011, we are focused on accelerating our pace of development in South Texas, improving our results through more efficient execution and exploiting other areas of our asset base. Our exposure to liquids rich production growth in South Texas, our oil production in South Louisiana, our growing leasehold acreage in the Austin Chalk and our deep exploration prospect inventory along the Gulf Coast together provide a uniquely positioned resource portfolio for investors to evaluate. For 2011, we are targeting an increase in production volumes of 25% to 30% over 2010 levels and reserves growth of 15% to 20% over 2010 levels. The Company has also begun to explore entering into select joint venture arrangements to help accelerate the drilling and development of particular fields.
Results of Operations
Summary Prior Year Comparison
In 2010 we had revenues of $438.4 million, an increase of 18% compared to 2009 levels. Our weighted average sales price received increased 28% to $52.42 per Boe for 2010 from $41.05 per Boe in 2009. This $68.0 million increase in revenues from 2009 levels was due to higher oil, natural gas, and NGL prices during 2010, offset somewhat by an 8% decrease in production mainly due to natural declines in our Southeast Louisiana fields.
Our overall costs and expenses decreased in 2010 by $70.9 million when compared to 2009 levels, but were higher on a Boe basis, as the 2009 period included a non-cash write-down of our oil and gas properties of $79.3 million in the first quarter. Depreciation, depletion and amortization expense decreased 2%, mainly due to higher reserves volumes and lower production when compared to the 2009 period, partially offset by a higher depletable property base in the 2010 period. Lease operating costs increased by 7% due to higher workover costs, natural gas processing costs, and saltwater disposal costs. Severance and other taxes increased 11% mainly due to increased oil and gas revenues.
Our net income for 2010 was $46.3 million, while our net loss in 2009 was $39.3 million.
Revenues
2010. Our revenues in 2010 increased by 18% compared to revenues in 2009 due to higher oil and gas prices after taking into account decreased production. Average oil prices that we received were 32% higher than those received during 2009, while natural gas prices were 14% higher, and NGL prices were 35% higher.
2009. Our revenues in 2009 decreased by 55% compared to revenues in 2008 primarily due to lower oil and gas prices, as oil, natural gas, and NGL prices we received in 2009 were 41%, 59%, and 45% lower, respectively, than the average prices we received a year earlier.
2008. Our 2008 production was adversely affected by Hurricanes Gustav and Ike. As a result of these hurricanes, approximately 0.8 MMBoe of production was shut-in during 2008 predominantly in Southeast Louisiana. All of this shut-in production was brought online in 2009.
Crude oil production was 47% of our production volumes in 2010, 48% in 2009, and 54% in 2008. Natural gas production was 39% of our production volumes in 2010, 39% in 2009, and 34% in 2008. The remaining production in each year was from natural gas liquids (NGLs).
Our properties are divided into the following four core areas, each of which includes the fields listed:
• South Texas
-
Olmos
AWP
Sun TSH
Las Tiendas
-
Eagle Ford
Hawkville AWP
Hawkville Artesia Wells
Hawkville Fasken
• Southeast Louisiana
Lake Washington
Bay de Chene
• Central Louisiana/East Texas
Brookeland
South Bearhead Creek
Masters Creek
Burr Ferry
• South Louisiana
Horseshoe Bayou/Bayou Sale
Jeanerette
Cote Blanche Island
The following table provides information regarding the changes in the sources of our oil and gas production and volumes for the years ended December 31, 2010, 2009, and 2008:
2010 Revenues Breakdown. Oil and gas sales in 2010 increased by 17%, or $64.9 million, from the level of those revenues for 2009, and our net production volumes in 2010 decreased by 8%, or 0.7 MMBoe, over net production volumes in 2009. Average prices for oil increased to $79.45 per Bbl in 2010 from $60.07 per Bbl in 2009. Average natural gas prices increased to $3.96 per Mcf in 2010 from $3.48 per Mcf in 2009. Average NGL prices increased to $42.44 per Bbl in 2010 from $31.36 per Bbl in 2009.
In 2010, our $64.9 million increase in oil, NGL, and natural gas sales resulted from:
•
Price variances that had a $97.8 million favorable impact on sales, of which $75.7 million was attributable to the 32% increase in average oil prices received, $12.6 million was attributable to the 35% increase in NGL prices, and $9.5 million was attributable to the 14% increase in average natural gas prices received; and
•
Volume variances that had a $32.9 million unfavorable impact on sales, with $26.5 million of decreases attributable to the 0.4 million Bbl decrease in oil production volumes, $1.4 million of decreases attributable to the less than 0.1 million Bbl decrease in NGL production volumes and $5.0 million of decreases attributable to the 1.4 Bcf decrease in natural gas production volumes.
2009 Revenues Breakdown. Oil and gas sales in 2009 decreased by 53%, or $422.1 million, from the level of those revenues for 2008, and our net production volumes in 2009 decreased by 10%, or 1.0 MMBoe, compared to net production volumes in 2008. Average prices for oil decreased to $60.07 per Bbl in 2009 from $101.38 per Bbl in 2008. Average natural gas prices decreased to $3.48 per Mcf in 2009 from $8.54 per Mcf in 2008. Average NGL prices decreased to $31.36 per Bbl in 2009 from $57.15 per Bbl in 2008.
In 2009, our $422.1 million decrease in oil, NGL, and natural gas sales resulted from:
•
Price variances that had a $317.2 million unfavorable impact on sales, of which $179.5 million was attributable to the 41% decrease in average oil prices received, $30.5 million was attributable to the 45% decrease in average NGL prices, and $107.2 million was attributable to the 59% decrease in average natural gas prices received; and
•
Volume variances that had a $104.9 million unfavorable impact on sales, with $108.9 million of decreases attributable to the 1.1 million Bbl decrease in oil production volumes, and $1.6 million of decreases attributable to the less than 0.1 million Bbl decrease in NGL production volumes, partially offset by an increase of $5.6 million due to the 0.7 Bcf increase in natural gas production volumes.
The following table provides additional information regarding our quarterly oil and gas sales from continuing operations excluding any effects of our hedging activities:
During 2010, 2009, and 2008, we recognized net gains (losses) of $0.7 million, ($1.4) million, and $26.1 million, respectively, related to our derivative activities. This activity is recorded in “Price-risk management and other, net” on the accompanying statements of operations. Had these gains been recognized in the oil and gas sales account, our average oil sales price would have been $79.52, $59.77 and $105.32 for 2010, 2009, and 2008, respectively, and our average natural gas price would have been $3.98, $3.47 and $8.77 for 2010, 2009, and 2008, respectively.
Costs and Expenses.
Our expenses in 2010 decreased $70.9 million, or 16%, compared to 2009 expenses for the reasons noted below.
Lease Operating Expenses (“LOE”). These expenses increased $5.2 million, or 7%, compared to the level of such expenses in 2009, while 2009 costs decreased $28.1 million, or 27% over 2008 levels. Lease operating costs increased during 2010 due to higher workover costs and other cost increases from lease supervision and repair & maintenance. These costs decreased in 2009 due to decreases in work-over costs, decreasing costs for industry goods and services, as well as lower natural gas and NGL processing costs. Clean-up and repair costs related to hurricanes Gustav and Ike totaled $3.7 million in 2008. Our lease operating costs per Boe produced were $9.84, $8.47, and $10.44 in 2010, 2009, and 2008, respectively.
Depreciation, Depletion and Amortization (“DD&A”). These expenses decreased $3.5 million, or 2%, in 2010, from 2009 levels and decreased $56.2 million, or 25% in 2009, from 2008 levels. The decrease in 2010 was due to lower production and higher reserves, partially offset by a higher depletion base. The decrease in 2009 was due to the write-down of oil and gas properties in the first quarter of 2009 which lowered our depletable base in addition to lower production, partially offset by lower reserves volumes and higher future development costs. Our DD&A rate per Boe of production was $19.52 in 2010, $18.34 in 2009, and $22.12 in 2008, resulting from increases in per unit cost of reserves additions in 2010 and decreases in per unit costs for 2009.
General and Administrative Expenses. These expenses increased $2.3 million, or 7%, from the level of such expenses in 2009, while 2009 general and administrative expenses, net, decreased $4.6 million, or 12%, from the level of such expenses in 2008. The increase in 2010 was primarily due to higher performance based compensation, partially offset by lower salaries and burdens. The decrease in 2009 was primarily due to lower stock compensation and lower salaries from the workforce reduction in early 2009, partially offset by lower capitalized amounts. For the years 2010, 2009, and 2008, our capitalized general and administrative costs totaled $24.6 million, $24.5 million, and $30.1 million, respectively. Our net general and administrative expenses per Boe produced increased to $4.37 per Boe in 2010 from $3.76 per Boe in 2009, compared to $3.85 per Boe in 2008. The portion of supervision fees recorded as a reduction to general and administrative expenses was $12.5 million for 2010, $11.4 million for 2009, and $15.8 million for 2008.
Severance and other taxes. These expenses increased $4.5 million, or 11%, from 2009 levels, while in 2009 these taxes decreased $39.1 million, or 49%, over 2008 levels. The increases in 2010 were due primarily to higher revenues from higher commodity prices. In 2009 the decreases were caused by lower commodity prices and lower production. Severance and other taxes, as a percentage of oil and gas sales, were approximately 10.5%, 11.1% and 10.1% in 2010, 2009 and 2008, respectively. The decrease in 2010 was primarily driven by a shift in product and regional mix as well as reduced tax rates for tight sand gas production related to South Texas Olmos and Eagle Ford completions. The increase in 2009 was caused by an increase in rates on Louisiana natural gas, which increased approximately 10% per Mcf produced, along with a slight increase in total revenues from oil production.
Interest. Our gross interest cost in 2010 was $40.8 million, of which $7.4 million was capitalized. Our total interest cost in 2009 was $36.8 million, of which $6.1 million was capitalized. Our total interest cost in 2008 was $39.1 million, of which $8.0 million was capitalized. The increase in interest expense in 2010 was primarily due to higher weighted average interest rates on outstanding debt in 2010 as compared to prior periods.
Income Taxes. Our effective income tax rate was 37.5%, 39.5% and 37.7% for 2010, 2009 and 2008, respectively. Our U.S. Federal income tax returns for 2002 forward, our Louisiana income tax returns from 1998 forward, our New Zealand income tax returns after 2004, and our Texas franchise tax returns after 2006 remain subject to examination by the taxing authorities. There are no material unresolved items related to periods previously audited by these taxing authorities. No other state returns are significant to our financial position
2009 and 2008 Ceiling Test Non-Cash Writedowns. In the first quarter of 2009, as a result of low oil and gas prices at March 31, 2009 we reported a non-cash write-down on a before-tax basis of $79.3 million ($50.0 million after tax) on our oil and natural gas properties. In the fourth quarter of 2008, as a result of low oil and natural gas prices at December 31, 2008, we reported a non-cash write-down on a before-tax basis of $754.3 million ($473.1 million after tax) on our oil and natural gas properties.
Net income (Loss). Our 2010 net income of $46.3 million was significantly improved, as compared to a 2009 net loss of $39.3 million (which included a $79.3 million non-cash write-down of oil and gas properties from the first quarter of 2009) and a 2008 net loss of $260.5 million (principally due to the $754.3 million non-cash write-down of oil and gas properties in December 2008). If the 2009 ceiling test write-down of $79.3 million ($50.0 million after-tax) and 2008 ceiling test write-down of $754.3 million ($473.1 million after tax) were to be excluded from 2009 and 2008 results, 2009’s income from continuing operations after tax would have been $11.0 million, while 2008’s income from continuing operations after tax would have been $216.0 million.
Known Price Trends and Uncertainties
Oil and natural gas prices historically have been volatile and this volatility is expected to continue in future periods. Factors such as worldwide economic conditions and credit availability, worldwide supply disruptions, weather conditions, fluctuating currency exchange rates, and political conditions in major oil producing regions, especially the Middle East, can cause fluctuations in the price of oil. Domestic natural gas prices remained high during much of 2008 when compared to longer-term historical prices but began falling in 2008 and continued to fall throughout 2009, showing slight improvement in late 2009 and through 2010. North American weather conditions, the industrial and consumer demand for natural gas, economic conditions and credit availability, storage levels of natural gas, the level of liquefied natural gas imports, and the availability and accessibility of natural gas deposits in North America can cause significant fluctuations in the price of natural gas.
Hurricane activity in the Gulf of Mexico may have a direct impact on our costs and operations. Extreme weather conditions in our Southeast Louisiana areas of activity can increase our costs, adversely affect our operations, and cause equipment or well damage, which damage may not be fully insured, and is no longer being covered by business interruption insurance.
Due to the cyclical nature of the oil and gas industry and during periods of increased levels of exploration and production in particular areas, such as we are currently experiencing in the Olmos and Eagle Ford formations, there is increased demand for drilling rigs, equipment, supplies, oilfield services, and trained and experienced personnel. The high demand in these areas has caused shortages and delays, which has raised costs and often delayed field development.
We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owner’s receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. Credit losses in 2010 and 2009 have been immaterial; we continue to monitor our purchasers of oil and gas for creditworthiness. We believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. For 2010, 2009 and 2008, oil and gas sales to Shell Oil Corporation and affiliates were 52%, 48% and 28% of total oil and gas sales, respectively; Chevron Corporation and its affiliates accounted for 25% of our 2008 total oil and gas sales. From certain customers we also obtain letters of credit or parent company guaranties, if applicable, to reduce risk of loss.
The oil and gas industry is subject to the indirect consequences of regulations that could expose us to risks of increasing environmental laws and regulations (and possibly increased costs of operations), delays in obtaining permits and licenses, and reduced demand for crude oil and natural gas, among others.
Liquidity and Capital Resources
Capital Expenditures
2010 Capital Expenditures. Our capital expenditures on a cash flow basis during 2010 were $353.6 million, while our accrual based capital expenditures were $421.0 million, as we significantly increased our accounts payable and accrued capital cost balances related to capital expenditures in the second half of 2010. Our cash flow basis amount of capital expenditures increased by $138.3 million as compared to those in the 2009 period mainly due to an increase in our spending on drilling and development in our South Texas core area. These 2010 expenditures were primarily funded by $259.0 million of cash provided by operating activities from continuing operations, and $140.1 million of proceeds from our public stock offering in November 2010.
Sources of Funds
Net Cash Provided by Operating Activities. For 2010, our net cash provided by operating activities from continuing operations was $259.0 million, representing a 15% increase as compared to $226.2 million generated during 2009. The 2010 increase was primarily due to an increase of $68.0 million in revenues, mainly attributable to higher oil and natural gas prices, partially offset by a combination of lower production, higher lease operating costs and higher severance taxes due to higher oil and gas sales. For 2009, our net cash provided by operating activities from continuing operations represented a 61% decrease from the $582.0 million generated during 2008, with this decrease primarily due to a $450.4 million decrease in revenues, mainly attributable to lower oil and natural gas prices in 2009, as well as lower production, partially offset by lower lease operating costs and severance taxes due to lower oil and gas sales.
2011 Capital Expenditures. We currently plan to finance our 2011 accrual based capital expenditures with our 2011 cash flow, cash on hand and potential line of credit borrowings. Our 2011 capital expenditures are currently budgeted at $430 million to $480 million, net of potential dispositions of non-strategic properties. Approximately 80% of our capital budget is targeted for our South Texas core area. The Company may also explore both joint venture arrangements for particular prospects and select property dispositions, in each case to accelerate drilling and development of its assets and diversify its risk profile. For 2011, we are targeting an increase in production volumes of 25% to 30% over 2010 levels and reserves growth of 15% to 20% over 2010 levels.
Existing Credit Facility. In September 2010 we renewed and extended our $500.0 million credit facility through October 2015,increasing our borrowing base to $300.0 million from $277.5 million. We had no amounts drawn under our credit facility at year-end of both 2009 and 2010. The next scheduled borrowing base review occurs in May 2011. Our revolving credit facility includes requirements to maintain certain minimum financial ratios (principally pertaining to adjusted working capital ratios and EBITDAX), and limitations on incurring other debt. We are in compliance with the provisions of this agreement and expect to remain in compliance with these provisions in future periods. Our available borrowings under our line of credit facility provide us liquidity. In light of credit market volatility in recent years which caused many financial institutions to experience liquidity issues, we periodically review the creditworthiness of the banks that fund our credit facility.
2010 Public Stock Offering. We raised $140.1 million net through an underwritten public stock offering in November 2010, issuing 4.04 million shares of our common stock at a price of $36.60 per share. The gross proceeds from these sales were approximately $147.8 million, before deducting underwriting commissions and issuance costs totaling $7.7 million. We used the proceeds from this stock sale to expand our South Texas drilling program and pay down a portion of the outstanding balance on our credit facility which increased liquidity.
2009 Public Stock Offering. We raised $108.8 million net through an underwritten public stock offering in August 2009, issuing 6.21 million shares of our common stock at a price of $18.50 per share. The gross proceeds from these sales were approximately $114.9 million, before deducting underwriting commissions and issuance costs totaling $6.1 million. We used the proceeds from this stock sale to pay down a portion of the outstanding balance on our credit facility which increased liquidity.
2009 Debt Issuance and Debt Retirements. We issued $225.0 million of 8-7/8% senior notes due 2020 in November 2009. In December 2009, we redeemed all $150.0 million of 7-5/8% senior notes due 2011 and recorded a charge of $4.0 million related to the redemption of these notes, which is recorded in “Debt retirement costs” on the accompanying consolidated statement of operations.
Financial Ratios
Working Capital and Debt to Capitalization. Our working capital increased from a surplus of $5.0 million at December 31, 2009, to a deficit of $2.0 million at December 31, 2010. The change primarily resulted from an increase in accounts payable and accrued liabilities plus an increase in accrued capital costs all of which are related to additional drilling activity in South Texas during 2010. Working capital, which is calculated as current assets less current liabilities, can be used to measure both a company's operational efficiency and short-term financial health. The Company uses this measure to track our short-term financial position. Our debt to capitalization ratio decreased to 35% at December 31, 2010, as compared to 41% at year-end 2009, as paid in capital increased due to our November 2010 stock offering, along with an increase in retained earnings due to our net income for 2010.
Contractual Commitments and Obligations
Our contractual commitments for the next five years and thereafter as of December 31, 2010 are as follows:
(1) Our most significant office lease is in Houston, Texas and it extends until 2015.
(2) Amounts shown by year are the net present value at December 31, 2010.
(3) Amounts shown represent fees for the minimum delivery obligations. Any amount of transportation utilized in excess of the minimum will reduce future year obligations
(4) The credit facility expires in October 2015 and these amounts exclude a $0.8 million standby letter of credit outstanding under this facility.
As of December 31, 2010 we had no off-balance sheet arrangements requiring disclosure pursuant to article 303(a) of Regulation S-K.
Proved Oil and Gas Reserves
We have added proved reserves over the past three years primarily through our drilling activities, including 36.7 MMBoe added in 2010, 8.5 MMBoe added in 2009, and 5.7 MMBoe added in 2008. The 2010 proved reserves additions from drilling activities consisted primarily of 30.2 MMBoe of additions to reserves in our South Texas area and 6.4 MMBoe of additions in the Burr Ferry Field. These additions were primarily proved undeveloped additions based on the results of the horizontal drilling program conducted in these areas during the year and would have been recorded as reserves additions under both the former and revised SEC reserves regulations. We obtained reasonable certainty regarding these reserves additions by applying the same methodologies that have been used historically in this area. We did not record material proved reserves revisions during 2010 as a result of the revised SEC reserves regulations. At year-end 2010, 45% of our total proved reserves were proved developed, compared with 50% at year-end 2009 and 53% at year-end 2008.
At year-end 2010, our proved reserves were 132.8 MMBoe with a PV-10 Value of $1.8 billion (PV-10 is a non-GAAP measure, see the section titled “Oil and Natural Gas Reserves” in our Property section for a reconciliation of this non-GAAP measure to the closest GAAP measure, the standardized measure), an increase in PV-10 of approximately $450 million from the prior year-end levels. In 2010, our proved natural gas reserves increased 132.4 Bcf, or 46%, while our proved oil reserves decreased 5.2 MMBbl, or 12%, and our NGL reserves increased 2.9 MMBbl, or 15%, for a total equivalent increase of 19.9 MMBoe, or 18%.
At year-end 2009, our proved reserves were 112.9 MMBoe with a PV-10 Value of $1.3 billion. In 2009, our proved natural gas reserves decreased 1.8 Bcf, or 1%, while our proved oil reserves decreased 5.2 MMBbl, or 10%, and our NGL reserves increased 2.0 MMBbl, or 11%, for a total equivalent decrease of 3.5 MMBoe, or 3%.
Our average natural gas price used in the PV-10 calculation for 2010 was $4.08 per Mcf. This average price during 2010 was a decrease from $3.78 per Mcf at year-end 2009, compared to $4.96 per Mcf at year-end 2008. Our average oil price used in the PV-10 calculation for 2010 was $78.31 per Bbl. This average price during 2010 was an increase from $59.76 per Bbl at year-end 2009, compared to $44.09 in 2008.
Critical Accounting Policies and New Accounting Pronouncements
Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized including internal costs incurred that are directly related to these activities and which are not related to production, general corporate overhead, or similar activities. Future development costs are estimated property-by-property based on current economic conditions and are amortized to expense as our capitalized oil and natural gas property costs are amortized.
We compute the provision for depreciation, depletion, and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. This calculation is done on a country-by-country basis.
The costs of unproved properties not being amortized are assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability, and available geological and geophysical information. As these factors may change from period to period, our evaluation of these factors will change. Any impairment assessed is added to the cost of proved properties being amortized.
The calculation of the provision for DD&A requires us to use estimates related to quantities of proved oil and natural gas reserves and estimates of unproved properties. For both reserves estimates (see discussion below) and the impairment of unproved properties (see discussion above), these processes are subjective, and results may change over time based on current information and industry conditions. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes, and excluding the recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using period-end prices, adjusted for the effects of hedging, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). We did not have any outstanding derivative instruments at December 31, 2010 that would materially affect this calculation.
We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. See the discussion above related to reserves estimation.
In 2009, as a result of lower oil and natural gas prices at March 31, 2009, we reported a non-cash write-down on a before-tax basis of $79.3 million ($50.0 million after tax) on our oil and gas properties. In the fourth quarter of 2008, we reported a non-cash write-down on a before-tax basis of $754.3 million ($473.1 million after tax) on our oil and gas properties due to lower oil and natural gas prices at the end of 2008.
Given the volatility of oil and natural gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and natural gas reserves could continue to change in the near-term. If oil and natural gas prices continue to decline from our period-end prices used in the Ceiling Test, even if only for a short period, it is possible that additional non-cash write-downs of oil and gas properties could occur in the future. If we have significant declines in our oil and natural gas reserves volumes, which also reduce our estimate of discounted future net cash flows from proved oil and natural gas reserves, additional non-cash write-downs of our oil and natural gas properties could occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be, thus we cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties if a decrease in oil and/or natural gas prices were to occur.”
New Accounting Pronouncements. In January 2010, the FASB issued ASU 2010-03 to amend oil and gas reserve accounting and disclosure guidance that aligns the oil and gas reserve estimation and disclosure requirements of Topic 932 (“Extractive Industries - Oil and Gas”) with the requirements of SEC release 33-8995. These releases are effective for financial statements issued on or after January 1, 2010. We have adopted this guidance for all reporting periods ending on or after December 31, 2009. This release changes the accounting and disclosure requirements surrounding oil and natural gas reserves and is intended to modernize and update the oil and gas disclosure requirements, to align them with current industry practices and to adapt to changes in technology. The most significant changes include:
·
Changes to prices used in reserves calculations, for use in both disclosures and accounting impairment tests. Prices will no longer be based on a single-day, period-end price. Rather, they will be based on either the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements.
·
Disclosure of probable and possible reserves is allowed.
·
The estimation of reserves will allow the use of reliable technology that was not previously recognized by the SEC.
·
Numerous changes in reserves disclosures mandated by SEC for Form 10-K.
·
Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.
These new requirements did not have a material impact upon our reserves estimation or earnings in the current period. The new rule requiring the preceding 12-month’s average price for oil and natural gas resulted in a lower average price for our reserves calculations for 2010 than if we had used the previous method utilizing the current price at period-end. These changes could have a material impact upon our financial statements in future periods due to the uncertainty of oil and gas prices.
Forward-Looking Information
The statements contained in this Annual Report on Form 10-K that are not historical facts, not limited to, statements found in “Business and Properties” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” are forward-looking statements as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, forecasted capital expenditures, drilling activity or methods, including the timing and location thereof, acquisition plans and proposals and dispositions, development activities, cost savings, capital budgets, production rates and volumes or forecasts thereof, hydrocarbon reserves, hydrocarbon prices, pricing or cost assumptions based on current and projected oil and gas prices, liquidity, cash flows, availability of capital, borrowing capacity, acquisition plans, regulatory matters, prospective legislation affecting the oil and gas industry, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, or changes in costs, future capital expenditures and overall economics and other variables surrounding our operations and future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “future,” “estimate,” “expect,” “budget,” “predict,” “anticipate,” “projected,” “should,” “assume,” “believe,” “target” or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions, upon current market conditions, and upon engineering and geologic information available at this time, and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and the Company’s financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by or on behalf of the Company. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for the Company’s oil and natural gas; effects of our indebtedness; success of our risk management techniques; inaccurate cost estimates; availability of and fluctuations in the prices of goods and services; the uncertainty of drilling results and reserve estimates; operating hazards; disruption of operations and damages from hurricanes or tropical storms; acquisition risks; requirements for capital or its availability; conditions in the financial and credit markets; general economic conditions; changes in geologic or engineering information; competition and government regulations; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or which are otherwise discussed in this annual report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in the Company’s other public reports, filings, and public statements.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. Significant declines in oil and natural gas prices began in the last half of 2008, and such pricing volatility has continued through 2009 with some improvement during the last half of 2009 and into 2010.
Our price-risk management policy permits the utilization of agreements and financial instruments (such as futures, forward contracts, swaps and options contracts) to mitigate price risk associated with fluctuations in oil and natural gas prices. We do not utilize these agreements and financial instruments for trading and only enter into derivative agreements with banks in our credit facility. Below is a description of the financial instruments we have utilized to hedge our exposure to price risk.
Price Floors - Between October and December 2010 we entered into additional natural gas price floors. These price floors cover natural gas production for January to April 2011 of 4,250,000 MMBtu with strike prices ranging between $3.77 and $4.30 per MMBtu.
Interest Rate Risk. Our senior notes and senior subordinated notes both have fixed interest rates, so consequently we are not exposed to cash flow risk from market interest rate changes on these notes. At December 31, 2010, we had no borrowings under our credit facility, which bears a floating rate of interest and therefore is susceptible to interest rate fluctuations. The result of a 10% fluctuation in the bank’s base rate would constitute 33 basis points and would not have a material adverse effect on our 2010 cash flows.
Income Tax Carryforwards. As of December 31, 2010, the Company has net tax carryforward assets of $23.1 million for federal net operating losses, $2.1 for federal alternative minimum tax credits and $7.8 million, net of a $1.7 million valuation allowance, for state tax net operating loss carryforwards which in management’s judgment will more likely than not be utilized to offset future taxable earnings. The Internal Revenue Service (IRS) commenced an examination of the Company’s 2008 U.S. income tax returns in October 2010.
The Company’s New Zealand subsidiaries have local income tax loss carryovers which are available if any future income is generated by these entities. As of December 31, 2010 the estimated U.S. dollar value of these loss carryover assets is $34.2 million. In management’s judgment it is less than more likely than not that the remaining carryover assets will be utilized. Accordingly, these carryover assets have been fully offset by a valuation allowance.
Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings, and senior notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the bank borrowings approximate the carrying amounts as of December 31, 2010 and 2009, and were determined based upon variable interest rates currently available to us for borrowings with similar terms. Based upon quoted market prices as of December 31, 2010 and 2009, the fair value of our senior notes due 2017, was 254.7 million, or 101.9% of face value, and $239.1 million, or 95.6% of face value, respectfully. Based upon quoted market prices as of December 31, 2010 and 2009, the fair value of our senior notes due 2020, which were issued in November 2009, was $242.3 million, or 107.7% of face value and $234.0 million, or 104% of face value, respectively. The carrying value of our senior notes due 2017 was $250.0 million at December 31, 2010 and 2009, while the carrying value of our senior notes due 2020 was $221.6 million and $221.4 million at December 31, 2010 and 2009, respectively.
Customer Credit Risk. We are exposed to the risk of financial non-performance by customers. Our ability to collect on sales to our customers is dependent on the liquidity of our customer base. Continued volatility in both credit and commodity markets may reduce the liquidity of our customer base. To manage customer credit risk, we monitor credit ratings of customers from certain customers we also obtain letters of credit, parent company guaranties if applicable, and other collateral as considered necessary to reduce risk of loss. Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.
Item 8.
Item 8. Financial Statements and Supplementary Data
Page
Management’s Report on Internal Control
Over Financial Reporting
Reports of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
Reports of Independent Registered Public Accounting Firm on Consolidated Financial Statements
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
2. Earnings Per Share
3. Provision (Benefit) for Income Taxes
4. Long-Term Debt
5. Commitments and Contingencies
6. Stockholders’ Equity
7. Related-Party Transactions
8. Discontinued Operations
9. Acquisitions and Dispositions
10. Fair Value Measurements
11. Consolidating Financial Information
Supplementary Information
Oil and Gas Operations (Unaudited)
Selected Quarterly Financial Data (Unaudited)
Management’s Report on Internal Control Over Financial Reporting
Management of Swift Energy Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is a process designed by, or under the supervision of, the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with U. S. generally accepted accounting principles.
Management of the Company assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment and those criteria, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2010.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on the Company’s internal control over financial reporting as of December 31, 2010, based on their audit. The Public Company Accounting Oversight Board (United States) standards require that they plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Their audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as they considered necessary in the circumstances.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of Swift Energy Company
We have audited Swift Energy Company and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2010 and our report dated February 24, 2011 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 24, 2011
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of Swift Energy Company
We have audited the accompanying consolidated balance sheets of Swift Energy Company and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2010 and 2009, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2011 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 24, 2011
Consolidated Balance Sheets
Swift Energy Company and Subsidiaries
(in thousands, except share amounts)
Consolidated Statements of Operations
Swift Energy Company and Subsidiaries
(in thousands, except share amounts)
Consolidated Statements of Stockholders’ Equity
Swift Energy Company and Subsidiaries
(in thousands, except per share amounts)
Consolidated Statements of Cash Flows
Swift Energy Company and Subsidiaries
(in thousands)
Notes to Consolidated Financial Statements
Swift Energy Company and Subsidiaries
1.
Significant Accounting Policies
Principles of Consolidation. The accompanying consolidated financial statements include the accounts of Swift Energy and its wholly owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and natural gas properties, with a focus on inland waters and onshore oil and natural gas reserves in Louisiana and Texas. Our undivided interests in gas processing plants are accounted for using the proportionate consolidation method, whereby our proportionate share of each entity’s assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements.
Discontinued Operations. Unless otherwise indicated, information presented in the notes to the financial statements relates only to Swift Energy’s continuing operations. Information related to discontinued operations is included in Note 8 and in some instances, where appropriate, is included as a separate disclosure within the individual footnotes.
Subsequent Events. We have evaluated subsequent events of our consolidated financial statements. There were no material subsequent events requiring additional disclosure in or amendments to these financial statements.
Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires us to make estimates and assumptions that affect the reported amount of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include:
·
the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties and the related present value of estimated future net cash flows there-from,
·
estimates related to the collectability of accounts receivable and the credit worthiness of our customers,
·
estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf,
·
estimates of future costs to develop and produce reserves,
·
accruals related to oil and gas revenues, capital expenditures and lease operating expenses,
·
estimates of insurance recoveries related to property damage, and the solvency of insurance providers,
·
estimates in the calculation of stock compensation expense,
·
estimates of our ownership in properties prior to final division of interest determination,
·
the estimated future cost and timing of asset retirement obligations,
·
estimates made in our income tax calculations, and
·
estimates in the calculation of the fair value of hedging assets.
While we are not aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period during which the adjustment occurs.
Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the years 2010, 2009, and 2008, such internal costs capitalized totaled $24.6 million, $24.5 million, and $30.1 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. For the years 2010, 2009, and 2008, capitalized interest on unproved properties totaled $7.4 million, $6.1 million, and $8.0 million, respectively. Interest not capitalized and general and administrative costs related to production and general corporate overhead are expensed as incurred.
The “Property and Equipment” balances on the accompanying consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances.
No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.
Future development costs are estimated property-by-property based on current economic conditions and are amortized to expense as our capitalized oil and natural gas property costs are amortized.
We compute the provision for depreciation, depletion, and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and natural gas properties-including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties-by an overall rate determined by dividing the physical units of oil and natural gas produced during the period by the total estimated units of proved oil and natural gas reserves at the beginning of the period. This calculation is done on a country-by-country basis, and the period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures, and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between 2 and 20 years. Repairs and maintenance are charged to expense as incurred. Renewals and betterments are capitalized.
Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved properties” and therefore subject to amortization. G&G costs incurred that are directly associated with specific unproved properties are capitalized in “Unproved properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes, and excluding the recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for the effects of hedging, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). Our hedges at year-end 2010 consisted of natural gas price floors that did not materially affect prices used in these calculations. This calculation is done on a country-by-country basis.
The calculation of the Ceiling Test and provision for depreciation, depletion, and amortization (“DD&A”) is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
In 2009, as a result of low oil and natural gas prices at March 31, 2009, we reported a non-cash write-down on a before-tax basis of $79.3 million on our oil and natural gas properties. For 2008, as a result of low oil and natural gas prices at December 31, 2008, we reported a fourth quarter non-cash write-down on a before-tax basis of $754.3 million on our oil and natural gas properties.
Given the volatility of oil and natural gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and natural gas reserves could continue to change in the near term. If oil and natural gas prices decline from our prices used in the Ceiling Test, it is possible that additional non-cash write-downs of oil and natural gas properties could occur in the future. If we have significant declines in our oil and natural gas reserves volumes, which also reduce our estimate of discounted future net cash flows from proved oil and natural gas reserves, additional non-cash write-downs of our oil and natural gas properties could occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be, thus we cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties if a decrease in oil and/or natural gas prices were to occur.
Revenue Recognition. Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Swift Energy uses the entitlement method of accounting in which we recognize our ownership interest in production as revenue. If our sales exceed our ownership share of production, the natural gas balancing payables are reported in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets. Natural gas balancing receivables are reported in “Other current assets” on the accompanying consolidated balance sheets when our ownership share of production exceeds sales. As of December 31, 2010, we did not have any material natural gas imbalances.
Reclassification of Prior Period Balances. Certain reclassifications have been made to prior period amounts to conform to the current year presentation.
Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings, and senior notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the bank borrowings approximate the carrying amounts as of December 31, 2010 and 2009, and were determined based upon variable interest rates currently available to us for borrowings with similar terms. Based upon quoted market prices as of December 31, 2010 and 2009, the fair value of our senior notes due 2017, was 254.7 million, or 101.88% of face value, and $239.1 million, or 95.6% of face value, respectfully. Based upon quoted market prices as of December 31, 2010 and 2009, the fair value of our senior notes due 2020, which were issued in November 2009, was $242.3 million, or 107.7% of face value and $234.0 million, or 104% of face value, respectively. The carrying value of our senior notes due 2017 was $250.0 million at December 31, 2010 and 2009, while the carrying value of our senior notes due 2020 was $221.6 million and $221.4 million at December 31, 2010 and 2009, respectively.
Accounts Receivable. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At December 31, 2010 and 2009, we had an allowance for doubtful accounts of approximately $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balance on the accompanying consolidated balance sheets.
At December 31, 2010 our “Accounts receivable” balance included $43.3 million for oil and gas sales, $2.3 million for joint interest owners and $1.4 million for other receivables. At December 31, 2009 our “Accounts receivable” balance included $36.4 million for oil and gas sales, $2.6 million for joint interest owners and $15.3 million for other receivables.
Debt Issuance Costs. Legal fees, accounting fees, underwriting fees, printing costs, and other direct expenses associated with extensions of our bank credit facility and public debt offerings were capitalized and are amortized on an effective interest basis over the life of each of the respective note offerings and credit facility.
The 7-1/8% senior notes due 2017 mature on June 1, 2017, and the balance of their issuance costs at December 31, 2010, was $3.0 million, net of accumulated amortization of $1.2 million. The 8-7/8% senior notes due 2020 mature on January 15, 2020, and the balance of their issuance costs at December 31, 2010, was $4.7 million, net of accumulated amortization of $0.3 million. The issuance costs associated with our revolving credit facility, which was extended in September 2010, had been capitalized and is being amortized over the life of the facility. The balance of revolving credit facility issuance costs at December 31, 2010, was $3.7 million, net of accumulated amortization of $3.2 million.
Insurance Claims. In 2008, we filed insurance claims related to 2008 Hurricanes Gustav and Ike. In April 2009, we settled our marine insurance claim relating to Hurricane Gustav for a net amount after deductible of $6.8 million, and in September 2009 settled our onshore claim relating to Hurricane Ike for a net amount after deductible of $0.8 million. Both of these reimbursements related to both capital costs and lease operating expense, and we have no additional hurricane related claims outstanding.
We have several open insurance claims filed in the ordinary course of business, none of which are material at the present time.
Price-Risk Management Activities. The Company follows FASB ASC 815-10, which requires that changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The guidance also establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) is recorded in the consolidated balance sheets as either an asset or a liability measured at its fair value. Hedge accounting for a qualifying hedge allows the gains and losses on derivatives to offset related results on the hedged item in the statement of operations and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. Changes in the fair value of derivatives that do not meet the criteria for hedge accounting, and the ineffective portion of the hedge, are recognized currently in income.
We have a price-risk management policy to use derivative instruments to protect against declines in oil and natural gas prices, mainly through the purchase of price floors and collars. During 2010, 2009, and 2008, we recognized net gains (losses) of $0.7 million, ($1.4) million, and $26.1 million, respectively, relating to our derivative activities. This activity is recorded in “Price-risk management and other, net” on the accompanying consolidated statements of operations. Had these gains and losses been recognized in the oil and gas sales account they would not materially change our per unit sales prices received. At December 31, 2010, the Company had recorded $0.1 million, net of taxes of less than $0.1 million, of derivative losses in “Accumulated other comprehensive loss, net of income tax” on the accompanying consolidated balance sheet. This amount represents the change in fair value for the effective portion of our hedging transactions that qualified as cash flow hedges. The ineffectiveness reported in “Price-risk management and other, net” for the twelve months of 2010 and 2009 was not material. All amounts currently held in “Accumulated other comprehensive loss, net of income tax” will be realized within the next four months when the forecasted sale of hedged production occurs.
At December 31, 2010, we had natural gas price floors in effect that covered a portion of our natural gas production for January to April 2011. These floors cover production of 4,250,000 MMBtu from January through April 2011 with strike prices ranging between $3.77 and $4.30 per MMBtu.
When we entered into these transactions discussed above, they were designated as a hedge of the variability in cash flows associated with the forecasted sale of oil and natural gas production. Changes in the fair value of a hedge that is highly effective and is designated and documented and qualifies as a cash flow hedge, to the extent that the hedge is effective, are recorded in “Accumulated other comprehensive loss, net of income tax.” When the hedged transactions are recorded upon the actual sale of the oil and natural gas, these gains or losses are reclassified from “Accumulated other comprehensive loss, net of income tax” on the accompanying consolidated balance sheets and recorded in “Price-risk management and other, net” on the accompanying consolidated statements of operations. The fair values of our derivatives are computed using the Black-Scholes-Merton option pricing model and are periodically verified against quotes from brokers. The fair value of these instruments at December 31, 2010 and 2009, was $0.3 million and $0.8 million, respectively, and was recognized on the accompanying consolidated balance sheets in “Other current assets.” At December 31, 2010, we had less than $0.1 million in receivables for settled gas hedges covering January 2011 production which are recognized on the accompanying balance sheet in “Accounts Receivables” and were subsequently collected in January 2011.
Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate including our wells in which we own up to a 100% working interest. Supervision fees, to the extent they do not exceed actual costs incurred, are recorded as a reduction to “General and administrative, net.” Our supervision fees are based on COPAS guidelines. The amount of supervision fees charged in 2010 and 2009 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operate was $12.5 million in 2010, $11.4 million in 2009, and $15.8 million in 2008.
Inventories. Inventories consist primarily of tubulars and other equipment that we expect to place in service in production operations. Inventories carried at cost (weighted average method) and are included in “Other current assets” on the accompanying consolidated balance sheets totaling $12.8 million and $10.0 million at December 31, 2010 and 2009, respectively.
Income Taxes. Under guidance contained in FASB ASC 740-10, deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws.
We follow the recognition and disclosure provisions under guidance contained in FASB ASC 740-10-25. Under this guidance, tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. As a result of adopting this guidance on January 1, 2007, we reported a $1.0 million decrease to our January 1, 2007 retained earnings balance and a corresponding increase to other long-term liabilities If recognized, these tax benefits would fully impact our effective tax rate
We do not believe the total of unrecognized tax positions will significantly increase or decrease during the next 12 months.
Our policy is to record interest and penalties relating to income taxes in income tax expense. As of December 31, 2010, we did not have any amount accrued for interest and penalties on uncertain tax positions.
Our U.S. Federal income tax returns for 2002 forward, our Louisiana income tax returns from 1998 forward, our New Zealand income tax returns after 2004, and our Texas franchise tax returns after 2006 remain subject to examination by the taxing authorities. There are no material unresolved items related to periods previously audited by these taxing authorities. No other state returns are significant to our financial position.
Accounts Payable and Accrued Liabilities. Included in “Accounts payable and accrued liabilities,” on the accompanying consolidated balance sheets, at December 31, 2010 and 2009 are trade payables of approximately $13.7 million and $2.7 million, respectively and accrued employee bonus and benefit payables of $11.5 million and $9.6 million. Also included are liabilities of approximately $8.1 million and $7.5 million at December 31, 2010 and 2009 respectively for outstanding checks. This represents the amounts by which checks issued, but not presented by vendors to the Company’s banks for collection, exceeded balances in the applicable disbursement bank accounts.
Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents.
Credit Risk Due to Certain Concentrations. We extend credit, primarily in the form of uncollateralized oil and gas sales and joint interest owners’ receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. From certain customers we also obtain letters of credit or parent company guaranties, if applicable, to reduce risk of loss. During 2010, 2009 and 2008, oil and gas sales to Shell Oil Company and affiliates accounted for 52%, 48% and 28% of our gross receipts, respectively. During 2008 sales to Chevron Corporation and its affiliates accounted for 25% of our total oil and gas receipts. Credit losses in each of the last three years were immaterial.
Restricted Cash. These balances primarily include amounts held in escrow accounts to satisfy domestic plugging and abandonment obligations. As of December 31, 2010 and 2009 these assets include approximately $1.3 million. These amounts are restricted as to their current use, and will be released when we have satisfied all plugging and abandonment obligations in certain fields. Restricted cash balances are reported in “Other long-term assets” on the accompanying consolidated balance sheets.
Accumulated Other Comprehensive Loss, Net of Income Tax. We follow the guidance contained in FASB ASC 220-10, which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income or loss includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company. At December 31, 2010, we recorded $0.1 million, net of taxes of less than $0.1 million, of derivative losses in “Accumulated other comprehensive loss, net of income tax” on the accompanying consolidated balance sheet. The components of accumulated other comprehensive loss and related tax effects for 2010 were as follows (in thousands):
Total comprehensive income (loss) was $46.4 million, ($39.6) million and ($260.1) million for 2010, 2009, and 2008, respectively.
Asset Retirement Obligation. We record these obligations in accordance with the guidance contained in FASB ASC 410-20. This guidance requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated on a unit-of-production basis over the estimated oil and natural gas reserves of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the full cost balance. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values.
The following provides a roll-forward of our asset retirement obligation (in thousands):
At December 31, 2010 and 2009, we had $8.7 million and $8.9 million, respectively, of our asset retirement obligation classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.
Public Stock Offering. In November 2010, we issued 4.04 million shares of our common stock in an underwritten public offering at a price of $36.60 per share. The gross proceeds from these sales were approximately $147.8 million, before deducting underwriting commissions and issuance costs totaling $7.7 million.
In August 2009, we issued 6.21 million shares of our common stock in an underwritten public offering at a price of $18.50 per share. The gross proceeds from these sales were approximately $114.9 million, before deducting underwriting commissions and issuance costs totaling $6.1 million.
New Accounting Pronouncements. In January 2010, the FASB issued ASU 2010-03 to amend oil and gas reserve accounting and disclosure guidance that aligns the oil and gas reserve estimation and disclosure requirements of Topic 932 (“Extractive Industries - Oil and Gas”) with the requirements of SEC Release No. 33-8995. This release is effective for financial statements issued on or after January 1, 2010. We have adopted this guidance for all reporting periods ending on or after December 31, 2009. This release changes the accounting and disclosure requirements surrounding oil and natural gas reserves and is intended to modernize and update the oil and gas disclosure requirements, to align them with current industry practices and to adapt to changes in technology. The most significant changes include:
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Changes to prices used in reserves calculations, for use in both disclosures and accounting impairment tests. Prices will no longer be based on a single-day, period-end price. Rather, they will be based on either the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements.
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Disclosure of probable and possible reserves is allowed.
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The estimation of reserves will allow the use of reliable technology that was not previously recognized by the SEC.
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Numerous changes in reserves disclosures mandated by SEC Form 10-K.
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Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.
These new requirements did not have a material impact upon our reserves estimation or earnings in the current period. These changes could have a material impact upon our financial statements in future periods due to the uncertainty of oil and gas prices.
2. Earnings Per Share
The Company computes earnings per share in accordance with FASB ASC 260-10. Under the guidance, unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are participating securities and, therefore, are included in computing earnings per share (EPS) pursuant to the two-class method. The two-class method determines earnings per share for each class of common stock and participating securities according to dividends or dividend equivalents and their respective participation rights in undistributed earnings. Unvested share-based payments that contain non-forfeitable rights to dividends or dividend equivalents are now included in the basic weighted average share calculation under the two-class method.
Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during each period. Diluted EPS for the year ended December 31, 2010 assumes, as of the beginning of the period, exercise of stock options using the treasury stock method. As we recognized a net loss for the years ended December 31, 2009 an 2008, the unvested share-based payments and stock options were not recognized in diluted earnings per share (“Diluted EPS”) calculations as they would be antidilutive. Certain of our stock options that would potentially dilute Basic EPS in the future were also antidilutive for the year ended December 31, 2010, and are discussed below.
The following is a reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS for the years ended December 31, 2010, 2009 and 2008 (in thousands, except per share amounts):
Options to purchase approximately 1.4 million shares at an average exercise price of $29.67 were outstanding at December 31, 2010, while options to purchase approximately 1.3 million shares at an average exercise price of $29.72 were outstanding at December 31, 2009, and options to purchase 1.1 million shares at an average exercise price of $33.22 were outstanding at December 31, 2008. Approximately 0.6 million stock options to purchase shares were not included in the computation of Diluted EPS for the year ended December 31, 2010, because these stock options were antidilutive, in that the sum of the stock option price, unrecognized compensation expense and excess tax benefits recognized as proceeds in the treasury stock method was greater than the average closing market price for the common shares during those periods. All of the 1.3 million and 1.1 million stock options to purchase shares were not included in the computation of Diluted EPS for the years ended December 31, 2009 and 2008, respectively, as they would be antidilutive given the net loss from continuing operations.
Employee restricted stock grants of less than 0.1 million shares were not included in the computation of Diluted EPS for the year ended December 31, 2010, because these restricted stock grants were antidilutive in that the sum of the unrecognized compensation expense and excess tax benefits recognized as proceeds under the treasury stock method was greater than the average closing market price for the common shares during that period. All of the 0.7 million and 0.6 million shares of employee restricted stock outstanding at December 31, 2009 and 2008, respectfully, were not included in the computation Diluted EPS, as they would be antidilutive given the net loss from continuing operations.
3. Provision (Benefit) for Income Taxes
Income (Loss) from continuing operations before taxes is as follows (in thousands):
The following is an analysis of the consolidated income tax provision (benefit) (in thousands):
Current taxes are primarily U.S. Federal income taxes. For 2010 current income tax expense is a net credit due to realization of U.S. Federal income tax refunds that were not anticipated at the end of 2009. These refunds were realized as a result of provisions within the Work, Homeownership, and Business Assistance Act of 2009 which allowed the Company to carry back its 2008 Federal net operating loss four years. The refunds were attributable to reductions in alternative minimum tax previously paid. The Company has no continuing operations in foreign jurisdictions.
Reconciliations of income taxes computed using the U.S. Federal statutory rate to the effective income tax rates are as follows (in thousands):
The primary upward adjustments in the effective tax rate above the U.S. statutory rate are the provision for state income taxes (computed net of the offsetting federal benefit) and non-deductible equity compensation. The provision for state income tax was a charge of $0.6 million for 2010 and a credit of $2.0 million and $12.0 million for 2009 and 2008, respectively. Non-deductible equity compensation increased tax expense by $0.9 million for 2010, $0.1 million for 2009, and by $0.8 million for 2008. In 2010 the Company revised its long-term state apportionment rates which resulted in a $1.7 million reduction to state income tax deferred liabilities. However, this adjustment also reduced our future expectation to realize benefits for Louisiana state tax loss carryovers. Accordingly we took a $1.7 million charge for a valuation allowance against our Louisiana loss carryovers. In 2009 the Company was able to reverse a previously recorded $1.1 million valuation allowance as a result of a tax gain realized on a joint venture transaction.
The tax effects of temporary differences representing the net deferred tax asset (liability) at December 31, 2010 and 2009 were as follows (in thousands):
Deferred tax assets decreased by $0.3 million. The federal net operating loss tax assets, net of NOLs for excess stock-based compensation, increased by $1.8 million due to a current year tax operating loss. Other items (consisting primarily of expenses accrued for books that are not currently deductible for tax) increased by $1.0 million; these increases were offset by the reduction in the alternative minimum tax credits, primarily the result of the Federal income tax refunds noted previously.
The total change in the deferred liability from 2009 to 2010 was an increase of $30.5 million. This increase is primarily attributable to a $30.1 million increase in the deferred liability for oil and gas exploration and development costs. This increase is primarily attributable to accelerated tax deductions for oil and natural gas exploration and development costs.
The federal net operating losses will expire between 2027 and 2030 if not utilized in earlier periods. The Company’s federal NOL tax assets for 2010 and 2009 were $30.7 million and $28.2 million, respectively, including deductions for excess stock-based compensation deductions. Excess stock-based compensation deductions in the amount of $7.6 million for 2010 and $6.9 million for 2009 represent stock-based compensation that have generated tax deductions that have not yet resulted in a cash tax benefit because the Company has NOL carryforwards. The Company plans to recognize the federal NOL tax assets associated with excess stock-based compensation tax deductions only when all other components of the federal NOL tax assets have been fully utilized. If and when the excess stock-based compensation related NOL tax assets are realized, the benefit will be credited directly to equity. The other primary carryover item is a $7.8 million net asset, net of a $1.7 million valuation allowance for State of Louisiana net operating loss carryovers. These loss carryforwards are scheduled to expire between 2013 and 2025.
Unrealized stock compensation accounts for $5.5 million in deferred tax assets. These amounts are attributable to stock compensation expenses accrued for employee stock options and restricted stock that are not realized for income tax purposes until exercised (for stock options) or vested (for restricted stock). The actual tax deductions realized may be significantly different than the accrued amounts depending on the market value of the stock on the date of exercise or vesting.
4. Long-Term Debt
Our long-term debt as of December 31, 2010 and 2009 is as follows (in thousands):
The maturities on our long-term debt are $250.0 million in 2017 and $225.0 million in 2020.
We have capitalized interest on our unproved properties in the amount of $7.4 million, $6.1 million and $8.0 million for the years ended December 31, 2010, 2009 and 2008, respectively.
Bank Borrowings. In September 2010 we renewed and extended our $500.0 million credit facility with a syndicate of nine banks through October 15, 2015, and have included a feature that allows the Company to increase the aggregate facility amount available up to $700.0 million with additional commitments from the lenders. We also increased our borrowing base to $300.0 million from $277.5 million. Debt issuance costs of approximately $3.6 million related to the extension of the credit facility were capitalized and are being amortized over the life of the facility.
At December 31, 2010 and 2009 we had no borrowings under our $500.0 million credit facility. The interest rate on our credit facility is either (a) the lead bank’s prime plus an applicable margin or (b) LIBOR plus an applicable margin. However with respect to (a) , if the lead bank’s prime rate is not higher than each of the federal funds rate plus ½%, and the adjusted London Interbank Offered Rate (“LIBOR”) plus 1%, the greatest of these three rates will then apply. The applicable margins vary depending on the level of outstanding debt with escalating rates of 100 to 200 basis points above the Alternative Base Rate and escalating rates of 200 to 300 basis points for LIBOR loans. The commitment fee associated with the unfunded portion of the borrowing base is set at 50 basis points. At December 31, 2010, the lead bank’s prime rate was 3.25%.
The terms of our credit facility include, among other restrictions, a limitation on the level of cash dividends (not to exceed $15.0 million in any fiscal year), a remaining aggregate limitation on purchases of our stock of $50.0 million, requirements as to maintenance of certain minimum financial ratios (principally pertaining to adjusted working capital ratios and EBITDAX) and limitations on incurring other debt. Since inception, no cash dividends have been declared on our common stock. We are currently in compliance with the provisions of this agreement. The credit facility is secured by our domestic oil and natural gas properties. Under the terms of the credit facility, we can increase the commitment amount to the total amount of the borrowing base at our discretion, subject to the terms of the credit agreement. The borrowing base amount is re-determined at least every six months starting with the next scheduled borrowing base review in May 2011.
Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $1.9 million in 2010, $5.2 million in 2009, and $8.6 million in 2008. The amount of commitment fees included in interest expense, net was $1.4 million in 2010, $0.7 million in 2009 and $0.5 million in 2008.
Senior Notes Due 2020. These notes consist of $225 million of 8-7/8% senior notes issued at 98.389% of par, which equates to an effective yield to maturity of 9-1/8%. The notes were issued on November 25, 2009 with an original discount of $3.6 million and will mature on January 15, 2020. The original discount of $3.6 million is recorded in “Long-Term Debt” on our consolidated balance sheets and will be amortized over the life of the note. The notes are senior unsecured obligations that rank equally with all of our existing and future senior unsecured indebtedness, are effectively subordinated to all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowing under our bank credit facility, and will rank senior to any future subordinated indebtedness of Swift Energy. Interest on these notes is payable semi-annually on January 15 and July 15 and commenced on November 25, 2009. On or after January 15, 2015, we may redeem some or all of these notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of 104.438% of principal, declining in twelve-month intervals to 100% in 2018 and thereafter. In addition, prior to January 15, 2013, we may redeem up to 35% of the principal amount of the notes with the net proceeds of qualified offerings of our equity at a redemption price of 108.875% of the principal amount of the notes, plus accrued and unpaid interest. We incurred approximately $5.0 million of debt issuance costs related to these notes, which is included in “Other Long-Term Assets” on the accompanying consolidated balance sheets and will be amortized to interest expense, net over the life of the notes using the effective interest method. In the event of certain changes in control of Swift Energy, each holder of notes will have the right to require us to repurchase all or any part of the notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. The terms of these notes include, among other restrictions, a limitation on how much of our own common stock we may repurchase. We are currently in compliance with the provisions of the indenture governing these senior notes.
Interest expense on the 8-7/8% senior notes due 2020, including amortization of debt issuance costs and debt discount, totaled $20.5 million and $2.0 million for the years ended December 31, 2010 and 2009, respectively.
Senior Notes Due 2017. These notes consist of $250.0 million of 7-1/8% senior notes due 2017, which were issued on June 1, 2007 at 100% of the principal amount and will mature on June 1, 2017. The notes are senior unsecured obligations that rank equally with all of our existing and future senior unsecured indebtedness, are effectively subordinated to all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowing under our bank credit facility, and will rank senior to any future subordinated indebtedness of Swift Energy. Interest on these notes is payable semi-annually on June 1 and December 1, and commenced on December 1, 2007. On or after June 1, 2012, we may redeem some or all of these notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of 103.563% of principal, declining in twelve-month intervals to 100% in 2015 and thereafter. We incurred approximately $4.2 million of debt issuance costs related to these notes, which is included in “Other Long-Term Assets” on the accompanying consolidated balance sheets and will be amortized to interest expense, net over the life of the notes using the effective interest method. In the event of certain changes in control of Swift Energy, each holder of notes will have the right to require us to repurchase all or any part of the notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. The terms of these notes include, among other restrictions, a limitation on how much of our own common stock we may repurchase. We are currently in compliance with the provisions of the indenture governing these senior notes.
Interest expense on the 7-1/8% senior notes due 2017, including amortization of debt issuance costs, totaled $18.4 million for the year ended December 31, 2010 and $18.1 million for both years ended December 31, 2009 and 2008.
Senior Notes Due 2011. These notes consisted of $150.0 million of 7-5/8% senior subordinated notes due July 2011, which were issued on June 23, 2004 and which were fully redeemed as of December 10, 2009. In the fourth quarter of 2009, we recorded a charge of $4.0 million related to the redemption of these notes. The costs were comprised of approximately $2.9 million of premium paid to redeem the notes, and $1.1 million to write-off unamortized debt issuance costs.
Interest expense on the 7-5/8% senior notes due 2011, including amortization of debt issuance costs totaled $11.4 million in 2009 and $12.0 million in 2008.
The maturities on our long-term debt are $250.0 million in 2017 and $225.0 million in 2020.
5. Commitments and Contingencies
Rental and lease expenses which were included in “General and administrative, net” on our accompanying consolidated statements of operations were $5.4 million in 2010, $4.2 million in 2009, and $3.2 million in 2008. Rental and lease expenses which were included in “Lease operating cost” on our accompanying consolidated statements of operations were $10.5 million in both 2010 and 2009, and $8.6 million in 2008. Our remaining minimum annual obligations under non-cancelable operating lease commitments were $6.0 million for 2011, $5.8 million for 2012, $5.6 million for 2013, $5.6 million for 2014, $0.9 million for 2015 and $23.9 million in the aggregate. The rental and lease expenses and remaining minimum annual obligations under non-cancelable operating lease commitments primarily relate to the lease of our office space in Houston, Texas which is a ten year lease and expires in 2015. This lease is renewable for two five-year periods at the prevailing office rental rates in the area at the time of renewal.
In the ordinary course of business, we have entered into agreements for drilling and completion services. The remaining commitments at December 31, 2010 for these services and materials totaled $100.7 million.
Our remaining gas transportation minimum delivery obligations were $1.4 million for 2011, $1.9 million for 2012, $2.3 million for 2013, $2.6 million for 2014 and $8.2 million in the aggregate.
In the ordinary course of business, we have been party to various legal actions, which arise primarily from our activities as operator of oil and natural gas wells. In management’s opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.
6. Stockholders’ Equity
Stock-Based Compensation Plans. We have three stock option plans that awards are currently granted under, the 2005 Stock Compensation Plan, which was adopted by our Board of Directors in March 2005 and was approved by shareholders at the 2005 annual meeting of shareholders, the 2001 Omnibus Stock Compensation Plan, which was adopted by our Board of Directors in February 2001 and was approved by shareholders at the 2001 annual meeting of shareholders, and the 1990 Non-Qualified Stock Option Plan solely for our independent directors. No further grants will be made under the 2001 Omnibus Stock Compensation Plan or the 1990 Non-Qualified Stock Option Plan, both of which were replaced by the 2005 Stock Compensation Plan, although options remain outstanding under both plans and are accordingly included in the tables below. In addition, we have an employee stock purchase plan and an employee stock ownership plan.
Under the 2005 plan, stock options and other equity based awards may be granted to employees, directors, and consultants, with directors only eligible to receive restricted awards. Under the 2001 plan, stock options and other equity based awards may be granted to employees. Under the 1990 non-qualified plan, non-employee members of our Board of Directors were automatically granted options to purchase shares of common stock on a formula basis. All three plans provide that the exercise prices equal 100% of the fair value of the common stock on the date of grant. Restricted stock grants become vested in various terms ranging from three years to five years, and stock options become exercisable in various terms ranging from one year to five years. Options granted typically expire ten years after the date of grant or earlier in the event of the optionee’s separation from employment. At the time the stock options are exercised, the cash received is credited to common stock and additional paid-in capital. Options issued under these plans also include a reload feature where additional options are granted at the then current market price when mature shares of Swift Energy common stock are used to satisfy the exercise price of an existing stock option grant. When Swift Energy common stock is used to satisfy the exercise price, the net shares actually issued are reflected in the accompanying statement of stockholders’ equity (see note 1 to table below). We view all awards of stock compensation as a single award with an expected life equal to the average expected life of component awards and amortize the award on a straight-line basis over the life of the award.
The employee stock purchase plan, which began in 1993, provides eligible employees the opportunity to acquire shares of Swift Energy common stock at a discount through payroll deductions. To date, employees have been allowed to authorize payroll deductions of up to 10% of their base salary, within IRS limitations and plan rules, during the plan year by making an election to participate prior to the start of a plan year. The purchase price for stock acquired under the plan is 85% of the lower of the closing price of our common stock as quoted on the New York Stock Exchange at the beginning or end of the plan year. Under this plan for the last three years, we have issued 66,564 shares at a price of $14.29 in 2010, 50,690 shares at a price of $14.29 in 2009, and 25,645 shares at a price of $36.83 in 2008 and registered 200,000 new shares in 2008. As of December 31, 2010, 92,378 shares remained available for issuance under this plan.
We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the stock is sold over the exercise price of the options. We receive an additional tax deduction when restricted stock vests at a higher value than the value used to recognize compensation expense at the date of grant. In accordance with guidance contained in FASB ASC 718, we are required to report excess tax benefits from the award of equity instruments as financing cash flows. However, under this guidance, a tax benefit and a credit to additional paid-in capital for the excess deduction is not be recognized until that deduction reduces taxes payable. For the twelve months ended December 31, 2010, we incurred a tax benefit of $0.1 million as restricted stock vested at a slightly overall higher value than the value used to record compensation expense at the date of grant. Because the Company is in a cumulative tax loss carryover position for income taxes, this excess benefit was not recorded. For the twelve months ended December 31, 2009, we recognized a tax benefit shortfall of $2.0 million as restricted stock vested at a lower value than the value used to record compensation expense at the date of grant, offset by a reduction to additional paid-in capital. Additionally, during 2009 we derecognized excess tax benefits credited to additional paid-in capital in 2008 of $1.5 million. This derecognition was due to lower than estimated taxable income for the 2008 income tax return and utilization of a loss carry back to obtain a partial tax refund for taxes paid in 2007. After these adjustments, no actual cash benefit was realized for the excess tax benefits for vesting of restricted stock and exercise of stock options during 2008.
Net cash proceeds from the exercise of stock options were $2.1 million, $0.3 million, and $8.3 million for the years ended December 31, 2010, 2009, and 2008 respectively. The actual income tax benefit from stock option exercises was $0.8 million, $0.1 million, and $4.1 million for the same periods.
Stock compensation expense for both stock options and restricted stock issued to both employees and non-employees is recorded in “General and Administrative, net” in the accompanying consolidated statements of operations, and was $9.3 million, $8.4 million, and $10.6 million for the years ended December 31, 2010, 2009, and 2008, respectively. Stock compensation recorded in lease operating cost was $0.3 million, $0.4 million, and $0.6 million for the years ended December 31, 2010, 2009, and 2008, respectively. We also capitalized $1.6 million, $2.1 million, and $4.5 million of stock compensation in 2010, 2009, and 2008, respectively.
Our shares available for future grant under our stock compensation plans were 1,903,660 at December 31, 2010. Each stock option granted reduces the aforementioned total by one share, while each restricted stock grant reduces the shares available for future grant by 1.44 shares.
Stock Options. We use the Black-Scholes-Merton option pricing model to estimate the fair value of stock option awards with the following weighted-average assumptions for the indicated periods:
The expected term for grants issued during or after 2008 has been based on an analysis of historical employee exercise behavior and considered all relevant factors including expected future employee exercise behavior. The expected term for grants issued prior to 2008 was calculated using the Securities and Exchange Commission Staff’s shortcut approach from Staff Accounting Bulletin No. 107. We have analyzed historical volatility, and based on an analysis of all relevant factors, we have used a 5.5 year look-back period to estimate expected volatility of our 2010, 2009 and 2008 stock option grants.
At December 31, 2010, there was $1.5 million of unrecognized compensation cost related to stock options which is expected to be recognized over a weighted-average period of 0.8 year. The following table represents stock option activity for the years ended December 31, 2010, 2009 and 2008:
1 The plans allow for the use of a “stock swap” in lieu of a cash exercise for options, under certain circumstances. The delivery of Swift Energy common stock, held by the optionee for a minimum of six months, which are considered mature shares, with a fair market value equal to the required purchase price of the shares to which the exercise relates, constitutes a valid “stock swap.” Options issued under a “stock swap” also include a reload feature where additional options are granted at the then current market price when mature shares of Swift stock are used to satisfy the exercise price of an existing stock option grant. The terms of the plans provide that the mature shares delivered, as full or partial payment in a “stock swap”, shall again be available for awards under the plans. In 2010 and 2008, 27,463 and 81,515 mature shares were delivered in “stock swap” transactions, respectively, which resulted in the issuance of an equal number of reload option grants. None were issued in 2009.
The aggregate intrinsic value and weighted average remaining contract life of options outstanding and exercisable at December 31, 2010 was $16.2 million and 5.6 years and $7.9 million and 3.7 years, respectively. The total intrinsic value of options exercised during the year ended December 31, 2010 was $2.6 million.
The following table summarizes information about stock options outstanding at December 31, 2010:
Restricted Stock. In 2010, 2009 and 2008, the Company issued 388,650, 433,210 and 314,440 shares, respectively, of restricted stock to employees, consultants, and directors. These shares vest over a three-year to five-year period and remain subject to forfeiture if vesting conditions are not met. The fair value of these shares when issued was approximately $25 per share in 2010, $12 per share in 2009 and $44 per share in 2008.
The compensation expense for these awards was determined based on the market price of our stock at the date of grant applied to the total number of shares that were anticipated to fully vest. As of December 31, 2010, we have unrecognized compensation expense of approximately $8.6 million associated with these awards which are expected to be recognized over a weighted-average period of 0.8 years. The total fair value of shares vested during the year ended December 31, 2010 was $9.0 million.
The following is a summary of our restricted stock issued to employees, consultants, and directors under these plans as of December 31, 2010, 2009, and 2008:
Employee Stock Ownership Plan. In 1996, we established an Employee Stock Ownership Plan (“ESOP”) effective January 1, 1996. All employees over the age of 21 with one year of service are participants. This plan has a three-year cliff vesting. The ESOP is designed to enable our employees to accumulate stock ownership. While there will be no employee contributions, participants will receive an allocation of stock that has been contributed by Swift Energy. Compensation expense is recognized upon vesting when such shares are released to employees. The plan may also acquire Swift Energy common stock, purchased at fair market value. The ESOP can borrow money from Swift Energy to buy Swift Energy common stock. ESOP payouts will be paid in a lump sum or installments, and the participants generally have the choice of receiving cash or stock. At December 31, 2010, 2009, and 2008, all of the ESOP compensation was earned. Our contribution to the ESOP plan totaled $0.2 million for the years ended December 31, 2010, 2009 and 2008, and were all made in common stock, and are recorded as “General and administrative, net” on the accompanying consolidated statements of operations. The shares of common stock contributed to the ESOP plan totaled 5,108, 8,347 and 11,898 shares for the 2010, 2009, and 2008 contributions, respectively.
Employee Savings Plan. We have a savings plan under Section 401(k) of the Internal Revenue Code. Eligible employees may make voluntary contributions into the 401(k) savings plan with Swift contributing on behalf of the eligible employee an amount equal to 100% of the first 2% of compensation and 75% of the next 4% of compensation based on the contributions made by the eligible employees. Our contributions to the 401(k) savings plan were $1.3 million for both 2010 and 2009 and $1.5 million for 2008, and are recorded as “General and administrative, net” on the accompanying consolidated statements of operations. The contributions in 2010, 2009, and 2008 were made all in common stock. The shares of common stock contributed to the 401(k) savings plan totaled 31,960, 50,988 and 82,125 shares for the 2010, 2009, and 2008 contributions, respectively.
Treasury Shares. In March 1997, our Board of Directors approved a common stock repurchase program that terminated as of June 30, 1999. Under this program, we spent approximately $13.3 million to acquire 927,774 shares in the open market at an average cost of $14.34 per share. At December 31, 2010, 441,525 shares remain in treasury (net of 726,015 shares used to fund the ESOP, 401(k) contributions and acquisitions) with a total cost of $9.8 million and are included in “Treasury stock held, at cost” on the accompanying consolidated balance sheets.
Shareholder Rights Plan. Our Rights Agreement was initially adopted by the Board of Directors in 1997 for a ten-year term. The Board of Directors renewed and extended the Rights Agreement for an additional ten-year term on December 21, 2006. Pursuant to the Rights Agreement as amended, for each share of Swift Energy common stock a holder has the right to purchase one one-thousandth of a share of Swift Energy preferred stock for $250 upon the occurrence of certain events triggered when a person or entity purchases 15% or more beneficial ownership of Swift Energy’s outstanding common stock. The rights are not exercisable by such 15% or more beneficial owner.
7. Related-Party Transactions
We receive research, technical writing, publishing, and website-related services from Tec-Com Inc., a corporation located in Knoxville, Tennessee and controlled and majority owned by the aunt of the Company’s Chairman of the Board and Chief Executive Officer. We paid approximately $0.6 million to Tec-Com for such services pursuant to the terms of the contract in both 2010 and 2009 and $0.7 million in 2008. The contract was renewed on July 1, 2010 on substantially the same terms as the previous contract and expires June 30, 2013. We believe that the terms of this contract are consistent with third party arrangements that provide similar services.
As a matter of corporate governance policy and practice, related party transactions are annually presented and considered by the Corporate Governance Committee of our Board of Directors in accordance with the Committee’s charter.
8. Discontinued Operations
In December 2007, we agreed to sell substantially all of our New Zealand assets. Accordingly, the New Zealand operations have been classified as discontinued operations in the consolidated statements of operations and cash flows and the assets and associated liabilities have been classified as held for sale in the consolidated balance sheets. In June 2008, we completed the sale of substantially all of our New Zealand assets for $82.7 million in cash after purchase price adjustments. Proceeds from this asset sale were used to pay down a portion of our credit facility. In August 2008, we completed the sale of our remaining New Zealand permit for $15.0 million; with three $5.0 million payments to be received nine months after the sale, 18 months after the sale, and 30 months after the sale. All payments under this sale agreement are secured by unconditional letters of credit, with the first two payments received in February 2009 and February 2010, respectively. Due to ongoing litigation, we have evaluated the situation and determined that certain revenue recognition criteria have not been met at this time for the permit sale, and have deferred the potential gain on this property sale pending further development of this litigation.
In accordance with guidance contained in FASB ASC 360-10, the results of operations for the New Zealand operations have been excluded from continuing operations and reported as discontinued operations for the current and prior periods. Furthermore, the assets included as part of this divestiture have been reclassified as held for sale in the consolidated balance sheets.
The book value of our remaining New Zealand permit is approximately $0.6 million at December 31, 2010.
The following table summarizes the amounts included in “Loss from Discontinued Operations, net of taxes” for all periods presented. These revenues and expenses were historically reported under our New Zealand operating segment, and are now reported as discontinued operations (in thousands except per share amounts):
Total income taxes differed from the amount computed by applying the statutory income tax rate to income from discontinued operations. The sources of these differences are as follows (in thousands):
There were no significant net deferred assets (liabilities) associated with assets held for sale at December 31, 2010 and 2009.
In 2007 the Company reported a non-cash write-down of properties held for sale that resulted in an estimated net deferred tax asset balance of $33.5 million, calculated using the New Zealand tax rate of 30%. This estimated net asset was attributable to New Zealand tax loss carryovers that are denominated in New Zealand dollars. As of December 31, 2010, the U.S. dollar value of the deferred asset was $34.2 million. As of December 31, 2010, 2009 and 2008, management assessed that the probability of generating additional taxable income to utilize these loss carryovers was not more likely than not. Since the Company’s net book value of this deferred tax asset is zero, no adjustments have been made to the provision for income tax from discontinued operations for the change in the gross deferred tax asset value.
The following presents the main classes of assets and liabilities associated with the New Zealand operations that were held for sale as of December 31, 2010 and 2009 (in thousands):
(1) Included in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheet.
9. Acquisitions and Dispositions
In November 2009, within our South Texas core area, we entered into a joint venture agreement with a large independent oil and gas producer active in the area for development and exploitation in and around the Eagle Ford Shale in McMullen County, Texas. The Company leased a 50% working interest in approximately 26,000 gross acres to the joint venture partner. Swift Energy retains a 50% working interest in the joint venture acreage and received approximately $26 million in cash consideration as well as consideration for approximately $13 million to fund future capital expenditures in the joint venture agreement, related to this transaction. As of December 31, 2010 we had approximately $0.2 million of the $13 million consideration remaining in our balance sheet. We used the proceeds from this joint venture to pay down a portion of the outstanding balance on our credit facility.
In August 2009, within our Central Louisiana/East Texas core area, we entered into a joint venture agreement with a large independent oil and gas producer active in the area for development and exploitation in and around the Burr Ferry field in Vernon Parish, Louisiana. The Company, as fee mineral owner, leased a 50% working interest in approximately 33,623 gross acres to the joint venture partner. Swift Energy retains a 50% working interest in the joint venture acreage as well as its fee mineral royalty rights, and received approximately $4.2 million related to this transaction. We used the proceeds from this joint venture to pay down a portion of the outstanding balance on our credit facility.
In August 2008, we announced the acquisition of oil and natural gas interests in South Texas from Crimson Energy Partners, L.P. a privately held company. The property interests are located in the Briscoe “A” lease in Dimmit County. Including an accrual of $0.6 million for purchase price adjustment reductions, we paid approximately $45.9 million in cash for these interests. After taking into account internal acquisition costs of $1.5 million, our total cost was $47.4 million. We allocated $44.0 million of the acquisition price to “Proved Properties,” $3.4 million to “Unproved Properties,” and recorded a liability for $0.2 million to “Asset retirement obligation” on our accompanying consolidated balance sheet. This acquisition was accounted for by the purchase method of accounting. We made this acquisition to increase our exploration and development opportunities in South Texas. The revenues and expenses from these properties have been included in our accompanying consolidated statement of operations from the date of acquisition forward and due to the short time period held were not material to our 2008 results.
10. Fair Value Measurements
FASB ASC 820-10 defines fair value, establishes guidelines for measuring fair value and expands disclosure about fair value measurements. It does not create or modify any current GAAP requirements to apply fair value accounting. However, it provides a single definition for fair value that is to be applied consistently for all prior accounting pronouncements. The adoption of this guidance did not have a material impact on our financial position or results of operations.
The following table presents our assets that are measured at fair value as of December 31, 2010 and are categorized using the fair value hierarchy. The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (in millions):
Level 1 - Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category include money market funds as they have comparable fair values for identical assets.
Level 2 - Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category include our commodity derivatives that we value using commonly accepted industry-standard models (such as Black-Scholes) which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources.
Level 3 - Uses unobservable inputs for assets or liabilities that are in non-active markets. We do not have any assets or liabilities in this category that are not supported by market activity and have significant unobservable inputs.
11. Condensed Consolidating Financial Information
Swift Energy Company is the issuer and Swift Energy Operating, LLC (a wholly owned indirect subsidiary of Swift Energy Company) is a guarantor of our senior subordinated notes due 2017 and 2020. The guarantees on our senior subordinated notes due 2017 and 2020 are full and unconditional. The following is condensed consolidating financial information for Swift Energy Company, Swift Energy Operating, LLC, and other subsidiaries:
Condensed Consolidating Balance Sheets
Condensed Consolidating Statements of Operations
Condensed Consolidating Statements of Cash Flow
Supplementary Information
Swift Energy Company and Subsidiaries
Oil and Gas Operations (Unaudited)
Capitalized Costs. The following table presents our aggregate capitalized costs relating to oil and natural gas producing activities and the related depreciation, depletion, and amortization (in thousands):
Of the $78.4 million of domestic unproved property costs (primarily seismic and lease acquisition costs) at December 31, 2010, excluded from the amortizable base, $28.7 million was incurred in 2010, $18.4 million was incurred in 2009, $8.1 million was incurred in 2008 and $23.2 million was incurred in prior years. We evaluate the majority of these unproved costs within a two to four year time frame.
Capitalized asset retirement obligations have been included in the Proved oil and gas properties as of December 31, 2010, 2009, and 2008.
Costs Incurred. The following table sets forth costs incurred related to our oil and natural gas operations (in thousands):
(1) These are actual amounts as incurred by year, including both proved and unproved lease costs. The annual lease acquisition amounts added to proved oil and gas properties in 2010, 2009, and 2008 were $50.3 million, $56.8 million, and $56.7 million, respectively. Domestic costs for seismic data acquisition, included above, were $6.1 million, 4.4 million, and $12.4 million in 2010, 2009, and 2008, respectively.
(2) Facility construction costs and capital costs have been included in development costs, and totaled $29.9 million, $18.4 million, and $48.2 million for the years ended December 31, 2010, 2009, and 2008, respectively.
(3) Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $24.6 million, $24.5 million, and $30.1 million in 2010, 2009, and 2008, respectively. In addition, the total includes $7.4 million, $6.1 million, and $8.0 million in 2010, 2009, and 2008, respectively, of capitalized interest on unproved properties.
(4) Asset retirement obligations incurred have been included in exploration, development and acquisition costs as applicable for the years ended December 31, 2010, 2009, and 2008.
Results of Operations (in thousands).
These results of operations do not include the gains (losses) from our hedging activities of $0.7 million, ($1.4) million and $26.1 million for 2010, 2009 and 2008, respectively. Our lease operating costs per Boe produced were $9.84 in 2010, $8.47 in 2009 and $10.44 in 2008.
We used our effective tax rate in each country to compute the provision (benefit) for income taxes in each year presented.
Supplementary Reserves Information. The following information presents estimates of our proved oil and natural gas reserves. Reserves were determined by us, and our domestic reserves were audited by H. J. Gruy and Associates, Inc. (“Gruy”), independent petroleum consultants. Gruy has audited 98% of our 2010 domestic proved reserves, 96% of our 2009 domestic proved reserves and 97% of our domestic proved reserves for 2008. The audit by Gruy conformed to the meaning of the term “reserves audit” as presented in Regulation S-K, Item 1202. Gruy’s audit was based upon review of production histories and other geological, economic, and engineering data provided by us. Gruy’s report dated February 18, 2011, is set forth as an exhibit to the Form 10-K Report for the year ended December 31, 2010, and includes assumptions and references to the definitions that serve as the basis for the audit of proved reserves and future net cash flows.
(1) Revisions of previous estimates are related to upward or downward variations based on current engineering information for production rates, volumetrics, and reservoir pressure. Additionally, changes in quantity estimates are affected by the increase or decrease in crude oil, NGL, and natural gas prices at each year-end. Proved reserves, as of December 31, 2010 and 2009 were based upon the preceding 12-months’ average price based on closing prices on the first business day of each month, or prices defined by existing contractual arrangements are held constant, for that year’s reserves calculation. Our hedges at year-end 2010 and 2009 did not materially affect prices used in these calculations. The 12-month average 2010 prices used in our calculations for domestic operations were $4.08 per Mcf of natural gas, $78.31 per barrel of oil, and $42.01 per barrel of NGL compared to $3.78 per Mcf of natural gas, $59.76 per barrel of oil, and $30.00 per barrel of NGL for the 12-month average 2009 prices. The year-end 2008 prices used for domestic operations were $6.65 per Mcf of natural gas, $93.24 per barrel of oil, and $56.28 per barrel of NGL for domestic operations.
(2) At December 31, 2010, 45% of our domestic reserves were proved developed, compared to 50% at December 31, 2009, and 53% at December 31, 2008.
Standardized Measure of Discounted Future Net Cash Flows. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows (in thousands):
The standardized measure of discounted future net cash flows from production of proved reserves at year-end 2010 was developed as follows:
1. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.
2. The estimated future gross revenues of proved reserves are based on the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements.
3. The future gross revenue streams are reduced by estimated future costs to develop and to produce the proved reserves, as well as asset retirement obligation costs, net of salvage value, based on year-end cost estimates and the estimated effect of future income taxes.
4. Future income taxes are computed by applying the statutory tax rate to future net cash flows reduced by the tax basis of the properties, the estimated permanent differences applicable to future oil and natural gas producing activities, and tax carry forwards.
The estimates of cash flows and reserves quantities shown above are based on the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. Our hedges at year-end 2010 consisted of natural gas price floors that did not have a material effect on prices used in these calculations. Subsequent changes to such oil and natural gas prices could have a significant impact on discounted future net cash flows. Under Securities and Exchange Commission rules, companies that follow the full-cost accounting method are required to make quarterly Ceiling Test calculations using hedge adjusted prices in effect as of the period end date presented (see Note 1 to the consolidated financial statements). Application of these rules during periods of relatively low oil and natural gas prices, even if of short-term seasonal duration, may result in non-cash write-downs.
The standardized measure of discounted future net cash flows is not intended to present the fair market value of our oil and natural gas property reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment, and the risks inherent in reserves estimates.
The standardized measure of discounted future net cash flows for 2008 was computed using rules in effect for that period.
The following are the principal sources of change in the standardized measure of discounted future net cash flows (in thousands):
Selected Quarterly Financial Data (Unaudited). The following table presents summarized quarterly financial information for the years ended December 31, 2010 and 2009 (in thousands, except per share data):
There were no extraordinary items in 2010 or 2009. Our New Zealand operations are accounted for as discontinued operations. In the first quarter of 2009, as a result of low oil and natural gas prices at March 31, 2009, we reported a non-cash write-down on a before-tax basis of $79.3 million ($50.0 million after tax) on our oil and natural gas properties.
The sum of the individual quarterly net income (loss) per common share amounts may not agree with year-to-date net income (loss) per common share as each quarterly computation is based on the weighted average number of common shares outstanding during that period. In addition, certain potentially dilutive securities were not included in certain of the quarterly computations of diluted net income (loss) per common share because to do so would have been antidilutive.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
We maintain disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, consisting of controls and other procedures designed to give reasonable assurance that information we are required to disclose in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to management, including our chief executive officer and our chief financial officer, to allow timely decisions regarding such required disclosure. The Company’s chief executive officer and chief financial officer have evaluated such disclosure controls and procedures as of the end of the period covered by this annual report on Form 10-K and have determined that such disclosure controls and procedures are effective.
There was no change in our internal control over financial reporting during the quarter ended December 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report On Internal Control Over Financial Reporting as of December 31, 2010 is included in Item 8. Financial Statements and Supplementary Data. The Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting is also included in Item 8.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
The information required under Item 10 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year-end in connection with our May 10, 2011, annual shareholders’ meeting is incorporated herein by reference.
Item 11.
Item 11. Executive Compensation
The information required under Item 11 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year-end in connection with our May 10, 2011, annual shareholders’ meeting is incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required under Item 12 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year-end in connection with our May 10, 2011, annual shareholders’ meeting is incorporated herein by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required under Item 13 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year-end in connection with our May 10, 2011, annual shareholders’ meeting is incorporated herein by reference.
Item 14.
Item 14. Principal Accountant Fees and Services
The information required under Item 14 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year-end in connection with our May 10, 2011, annual shareholders’ meeting is incorporated by reference.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules.
1. The following consolidated financial statements of Swift Energy Company together with the report thereon of Ernst & Young LLP dated February 23, 2011, and the data contained therein are included in Item 8 hereof:
Management’s Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
2. Financial Statement Schedules
[None]
3. Exhibits
3.1
Certificate of Formation of Swift Energy Company (incorporated by reference as Exhibit 3.1 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2009 filed November 3, 2009, File No. 1-08754).
3.2
Second Amended and Restated Bylaws of Swift Energy Company, effective October 30, 2009 (incorporated by reference as Exhibit 3.2 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2009 filed November 3, 2009, File No. 1-08754).
3.3
Certificate of Designation of Series A Junior Participating Preferred Stock of Swift Energy Company (incorporated by reference as Exhibit 3.4 to Swift Energy Company’s Form 8-K filed December 29, 2005, File No. 1-08754).
4.1
Indenture dated as of May 19, 2009, between Swift Energy Company and Wells Fargo Bank, National Association, as Trustee (incorporated by reference as Exhibit 4.1 to Swift Energy Company’s Form S-3 filed May 19, 2009, and amended June 17 and June 26, 2009, File No. 1-08754).
4.2
First Supplemental Indenture dated as of November 25, 2009, between Swift Energy Company, Swift Energy Operating, LLC, and Wells Fargo Bank, National Association, as Trustee, including the form of 8 7/8% Senior Notes (incorporated by reference as Exhibit 4.1 to Swift Energy Company’s Form 8-K filed December 2, 2009, File No. 1-08754).
4.3
Amended and Restated Rights Agreement between Swift Energy Company and American Stock Transfer & Trust Company, dated March 31, 1999 (incorporated by reference to Swift Energy Company’s Amendment No. 1 to Form 8-A filed April 7, 1999, File No. 1-08754).
4.4
Amendment No. 1 to the Rights Agreement dated December 12, 2005 between Swift Energy Company and American Stock Transfer & Trust Company, as Rights Agent (incorporated by reference as Exhibit 4.3 to Swift Energy Company’s Form 8-K filed December 29, 2005, File No. 1-08754).
4.5
Assignment, Assumption, Amendment and Novation Agreement between Swift Energy Company, New Swift Energy Company and American Stock Transfer & Trust Company, as Rights Agent effective at 9:00 a.m. local time in Austin, Texas on December 28, 2005 (incorporated by reference as Exhibit 4.4 to Swift Energy Company’s Form 8-K filed December 29, 2005, File No. 1-08754).
4.6
Amendment No. 2 to the Rights Agreement dated December 21, 2006 between Swift Energy Company and American Stock Transfer & Trust Company, as Rights Agent (incorporated by reference as Exhibit 4.1 to Swift Energy Company’s Form 8-K filed December 22, 2006, File No. 1-08754).
4.7
Form of indenture dated as of May 16, 2007 between Swift Energy Company and Wells Fargo Bank, National Association (incorporated by reference as Exhibit 4.1 to Swift Energy Company’s Registration Statement on Form S-3 filed May 17, 2007, File No. 333-143034).
4.8
First Supplemental Indenture dated as of June 1, 2007, between Swift Energy Company, Swift Energy Operating, LLC and Wells Fargo Bank, National Association relating to the 7-1/8% Senior Notes due 2017 (incorporated by reference as Exhibit 4.1 to Swift Energy Company’s Form 8-K filed June 7, 2007, File No. 1-08754).
10.1+
Amended and Restated Swift Energy Company 1990 Nonqualified Stock Option Plan, as of May 13, 1997 (incorporated by reference from Swift Energy Company’s definitive proxy statement for the annual shareholders meeting filed April 14, 1997, File No. 1-08754).
10.2+
Amendment to the Swift Energy Company 1990 Stock Compensation Plan, as of May 9, 2000 (incorporated by reference as Exhibit 4.2 to the Swift Energy Company registration statement No. 333-67242 on Form S-8 filed August 10, 2001, File No. 1-08754).
10.3+
Swift Energy Company 2001 Omnibus Stock Compensation Plan, as of January 1, 2001 (incorporated by reference as Exhibit 4.3 to the Swift Energy Company registration statement no. 333-67242 on Form S-8 filed August 10, 2001, File No. 1-08754).
10.4
Form of Indemnity Agreement for Swift Energy Company officers (incorporated by reference as Exhibit 10.9 to Swift Energy Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-08754).
10.5
Form of Indemnity Agreement for Swift Energy Company directors (incorporated by reference as Exhibit 10.10 to Swift Energy Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-08754).
10.6+
Consulting Agreement between Swift Energy Company and Virgil N. Swift effective as of July 1, 2006 (incorporated by reference as Exhibit 10.1 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2006 filed May 5, 2006, File No. 1-08754).
10.7+
Forms of agreements for grant of incentive stock options and forms of agreement for grant of restricted stock under Swift Energy Company 2005 Stock Compensation Plan (incorporated by reference as Exhibit 10.19 to Swift Energy Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005 filed March 1, 2006, File No. 1-08754).
10.8
Second Amended and Restated Credit Agreement effective as of September 21, 2010, among Swift Energy Company, Swift Energy Operating, LLC and JPMorgan Chase Bank, N.A. as Administrative Agent, BNP Paribas and Wells Fargo Bank, N.A. as Co-Syndication Agents, Bank of Scotland PLC and Societe Generale, as Co-Documentation Agents, and the Lenders party thereto (incorporated by reference as Exhibit 10.01 to the Swift Energy Company‘s Form 8-K filed September 27, 2010, File No. 1-08754).
10.9
Eighth Amendment to Lease Agreement between Swift Energy Company and Greenspoint Plaza Limited Partnership dated as of June 30, 2004 (incorporated by reference as Exhibit 10.1 to the Swift Energy Company Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 filed August 6, 2004, File No. 1-08754).
10.10+
Amendment No. 1 to the Swift Energy Company First Amended and Restated 2005 Stock Compensation Plan (incorporated by reference as Exhibit 10.1 to Swift Energy Company’s Form 8-K filed April 1, 2009, File No. 1-08745).
10.11+
Amendment No. 2 to the Swift Energy Company First Amended and Restated 2005 Stock Compensation Plan (incorporated by reference as Exhibit 10.2 to Swift Energy Company’s Form 8-K filed May 14, 2009, File No. 1-08754).
10.12+
Amendment No. 3 to the Swift Energy Company First Amended and Restated 2005 Stock Compensation Plan (incorporated by reference as Exhibit 10.1 to Swift Energy Company’s Form 8-K filed May 12, 2010, File No. 1-08754).
10.13
Asset Purchase and Sale Agreement between Escondido Resources LP and Swift Energy Operating, LLC dated as of September 4, 2007 but effective as of July 1, 2007 (incorporated by reference as Exhibit 99.1 to the Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 filed November 1, 2007).
10.14
Agreement for Sale and Purchase of Assets between Swift Energy New Zealand Limited, Swift Energy New Zealand Holdings Limited, Southern Petroleum (New Zealand) Exploration Limited, Origin Energy Recourses NZ (SPV1) Limited, Origin Energy Resources NZ (SPV2) Limited and Origin Energy Limited effective December 1, 2007 (incorporated by reference as Exhibit 10.35 to Swift Energy Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2007, File No. 1-08754).
10.15+
First Amended and Restated 2005 Stock Compensation Plan dated November 4, 2008 (incorporated by reference as Exhibit 10.1 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2008 filed November 6, 2008).
10.16+
Swift Energy Company Change of Control Severance Plan dated November 4, 2008 (incorporated by reference as Exhibit 10.2 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2008 filed November 6, 2008).
10.17+
Second Amended and Restated Executive Employment Agreement between Swift Energy Company and Terry E. Swift dated November 4, 2008 (incorporated by reference as Exhibit 10.3 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2008 filed November 6, 2008).
10.18+
Second Amended and Restated Executive Employment Agreement between Swift Energy Company and Bruce H. Vincent dated November 4, 2008 (incorporated by reference as Exhibit 10.4 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2008 filed November 6, 2008).
10.19+
Second Amended and Restated Executive Employment Agreement between Swift Energy Company and Alton D. Heckaman dated November 4, 2008 (incorporated by reference as Exhibit 10.5 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2008 filed November 6, 2008).
10.20+
Executive Employment Agreement between Swift Energy Company and Robert J. Banks dated November 4, 2008 (incorporated by reference as Exhibit 10.6 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2008 filed November 6, 2008).
10.21+
Amended and Restated Executive Employment Agreement between Swift Energy Company and James P. Mitchell dated November 4, 2008 (incorporated by reference as Exhibit 10.8 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2008 filed November 6, 2008).
10.22+
Second Amended and Restated Executive Employment Agreement between Swift Energy Company and James M. Kitterman dated November 4, 2008 (incorporated by reference as Exhibit 10.7 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2008 filed November 6, 2008).
10.23+
Employee Stock Purchase Plan, Generally Amended and Restated as of January 1, 2009.
12 *
Swift Energy Company Ratio of Earnings to Fixed Charges.
21 *
List of Subsidiaries of Swift Energy Company.
23.1 *
Consent of H.J. Gruy and Associates, Inc.
23.2 *
Consent of Ernst & Young LLP as to incorporation by reference regarding Forms S-8 and S-3 Registration Statements.
31.1 *
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32 *
Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*
The summary of H.J. Gruy and Associates, Inc. reported February 18, 2011.
* Filed herewith.
+ Management contract or compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant, Swift Energy Company, has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SWIFT ENERGY COMPANY
By: /s/ Terry E. Swift
Terry E. Swift
Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant, Swift Energy Company, and in the capacities and on the dates indicated:
Signatures
Title
Date
Director
/s/ Terry E. Swift
Chief Executive Officer
February 24, 2011
Terry E. Swift
Executive Vice-President
/s/ Alton D. Heckaman, Jr.
Principal Financial Officer
February 24, 2011
Alton D. Heckaman, Jr.
Vice-President
Controller
/s/ Barry S. Turcotte
Principal Accounting Officer
February 24, 2011
Barry S. Turcotte
/s/ Deanna L. Cannon
Director
February 23, 2011
Deanna L. Cannon
/s/ Douglas J. Lanier
Director
February 23, 2011
Douglas J. Lanier
/s/Greg Matiuk
Director
February 23, 2011
Greg Matiuk
/s/ Clyde W. Smith, Jr.
Director
February 23, 2011
Clyde W. Smith, Jr.
/s/ Charles J. Swindells
Director
February 23, 2011
Charles J. Swindells
/s/ Bruce H. Vincent
Director
February 24, 2011
Bruce H. Vincent