Item 1 A.
Risk Factors
Item 1 B.
Unresolved Staff Comments
Item 2.
Properties
Petroleum and Natural Gas Properties
Company Reserve Estimates
Volumes, Prices and Operating Expenses
Development, Exploration and Acquisition Capital Expenditures
Productive Gas Wells
Oil and Gas Acreage
Drilling Activity
Office Space
Item 3.
Legal Proceedings
Item 4.
Submission of Matters to a Vote of Security Holders
Part II
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Securities Authorized for Issuance Under Equity Compensation Plans
Item 6.
Selected Financial Data
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward Looking Statements
Overview
Drilling Activity
Forward Sales Contract
Derivatives
PART I
ITEM 1 - BUSINESS
Business of Gasco
Gasco Energy, Inc. (“Gasco,” “the Company,” “we,” “our” or “us”) was incorporated under the laws of the State of Nevada on April 21, 1997 and operated as a “shell” company until December 31, 1999. Gasco is a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon resources, primarily in the Rocky Mountain region. Our principal business strategy is to enhance stockholder value by using technologies new to a specific area to generate and develop high-potential exploitation resources in this area. Our principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to these leases. We are currently focusing our drilling efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Wasatch, Mesaverde and Blackhawk, Mancos and Dakota/Morrison formations. As of December 31, 2007, we held interests in 296,874 gross acres (188,817 net acres) located in Utah, Wyoming, California and Nevada. As of December 31, 2007, we held an interest in 112 gross producing wells (69.7 wells, net to our interest) and 5 shut-in wells (5.0 net) located on these properties.
During 2007, we spudded 25 gross operated wells (9.6 net) and reached total depth on 28 gross operated wells (10.9 net) in the Riverbend Project. We also participated in one (0.25 net) outside operated well that was spud and reached total depth during the year. Initial completion operations were conducted on 23 operated wells (10.1 net) and one well bore (1.0 net) was re-entered to complete behind-pipe pay zones. We also participated in the completion of one outside operated well (0.25 net) for the year. As of December 31, 2007, we operated 107 gross producing wells with five additional operated wells awaiting initial completion activities and 37 wells awaiting up-hole recompletions. Currently, we have two drilling rigs under contract, one through April 2010 and the other on a well-by-well basis.
History
Gasco (formerly known as San Joaquin Resources Inc. (“SJRI”)) was incorporated on April 21, 1997 under the laws of the State of Nevada, as “LEK International, Inc.” The Company operated as a “shell” company until December 31, 1999, when the Company combined with San Joaquin Oil & Gas Ltd., a Nevada corporation (“Oil & Gas”). As a result of that transaction, Oil & Gas became a wholly-owned subsidiary of Gasco.
In February 2001, a subsidiary of the Company merged with Gasco Production Company (formerly known as Pannonian Energy, Inc.) (“GPC”), a private corporation incorporated under the laws of the State of Delaware. GPC was an independent energy company engaged in the exploration, development and acquisition of crude oil and natural gas reserves in the western United States. Prior to the closing of the merger, GPC divested itself of all assets not associated with its “Riverbend” area of interest (the “non-Riverbend assets”). These “spin-offs” were accounted for at the recorded amounts. The net book value of the non-Riverbend assets in the
United States transferred, including cash of $1,000,000 and liabilities of $555,185, was approximately $1,850,000. The non-Riverbend assets located outside of the United States were held by Pannonian International Ltd. (“PIL”), the shares of which were distributed to the GPC stockholders. The net book value of PIL as of the date of distribution was approximately $174,000.
Certain shareholders of SJRI surrendered for cancellation 2,438,930 common shares of the Company’s capital stock on completion of the transaction contemplated by the GPC Agreement.
Upon completion of the transaction, GPC became a wholly-owned subsidiary of the Company. However, since this transaction resulted in the existing shareholders of GPC acquiring control of the Company, for financial reporting purposes the business combination was accounted for as a reverse acquisition with GPC as the accounting acquirer.
Acquisition, Exploration and Development Expenses
During the years ended December 31, 2007, 2006 and 2005, we incurred $82,496,756, $87,270,883 and $50,069,968, respectively, for acquisitions, development and exploration activities. During 2007, we entered into a definitive agreement with a subsidiary of NFR Energy, LLC (“NFR”) whereby the subsidiary of NFR will participate in a 30-well drilling program in our Riverbend Project through the second quarter of 2008. The terms of the agreement allow for the subsidiary of NFR to earn two-thirds of our interest in each 40-acre drilling location in exchange for paying its share of costs, including a per-well location fee paid to Gasco as the operator of the project.
On December 14, 2007, we closed the previously announced purchase of Brek Energy Corporation (“Brek”). As a result of this acquisition (the “Brek Acquisition”), Gasco acquired approximately 17,000 net acres in the Uinta Basin of Utah, approximately 7,200 net acres in the Green River Basin of Wyoming and additional working interests in ten producing properties in which Gasco was already the operator and holds working interests. The acquisition is expected to simplify Gasco’s acreage portfolio by absorbing a working interest partner that previously owned approximately 14% of Gasco’s undeveloped acreage in Utah and Wyoming. Gasco does not expect to incur any additional overhead expenses as a result of the acquisition.
Under the terms of the Brek Acquisition, a wholly-owned subsidiary of Gasco merged with and into Brek. As part of the transaction, Brek’s President and CEO, who owned approximately 18% of the outstanding common stock of Brek, agreed to deposit 550,000 shares of Gasco common stock acquired in the transaction in escrow to satisfy any claims with respect to breaches of representations and warranties of Brek for a period of one year following the merger.
In connection with the acquisition, Gasco issued 10,999,868 shares of its common stock to Brek’s shareholders. The shares of common stock issued to Brek shareholders were valued at $2.76 per share, which was the average value of the Company’s common stock for two days before and after the merger agreement was signed. The total purchase price of the Brek Acquisition was approximately $30,749,300.
Principal Products or Services and Markets
Gasco focuses its exploitation activities on locating natural gas and crude petroleum. The principal markets for these commodities are natural gas transmission pipeline and marketing companies, utilities, refining companies and private industry end-users. Historically, nearly all of the Company’s sales have been to a few customers. During each of the years ended December 31, 2007, 2006 and 2005, over 80% of our production was sold to one customer, ConocoPhillips. However, Gasco does not believe that the loss of a single purchaser, including ConocoPhillips, would materially affect the Company’s business because there are numerous other potential purchasers in the areas in which Gasco sells its production. For the years ended December 31, 2007, 2006 and 2005, purchases by the following company exceeded 10% of the total oil and gas revenues of the Company.
Competitive Business Conditions, Competitive Position in the Industry and Methods of Competition
The Company’s natural gas and petroleum exploration activities take place in a highly competitive and speculative business atmosphere. In seeking suitable natural gas and petroleum properties for acquisition, Gasco competes with a number of other companies operating in its areas of interest, including large oil and gas companies and other independent operators with greater financial and other resources. Management does not believe that Gasco’s competitive position in the petroleum and natural gas industry will be significant.
There is a competitive market for hiring field and technical personnel and obtaining drilling rigs and services. The current high level of drilling activity in Gasco’s areas of exploration may have a significant adverse impact on the timing and profitability of Gasco’s operations. In addition, as discussed under “Item 1A
ITEM 1A. Risk Factors
Due to the nature of the Company’s business and the present stage of exploration on its oil and gas prospects, the following risk factors apply to Gasco’s operations:
We have incurred losses since our inception and may continue to incur losses in the future.
To date, our operations have not generated sufficient operating cash flows to provide working capital for our ongoing overhead, the funding of our lease acquisitions and the exploration and development of our properties. Without adequate financing, we may not be able to successfully develop any prospects that we have or acquire and we may not achieve profitability from operations in the near future or at all.
During the years ended December 31, 2007, 2006 and 2005, we incurred a net loss of $104,373,921, $55,817,767 and $37,635, respectively. As of December 31, 2007, we had an accumulated deficit of $189,726,914. Our failure to achieve profitability in the future could adversely affect the trading price of our common stock or our ability to raise additional capital. Any of these circumstances could have a material adverse effect on our financial condition and results of operations.
The volatility of natural gas and oil prices could have a material adverse effect on our business.
Our revenue, profitability and cash flow depend upon the prices and demand for natural gas and oil. Moreover, changes in natural gas and oil prices have a significant impact on the value of our reserves. The markets for these commodities are very volatile and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Prices for natural gas and oil may fluctuate widely in response to a variety of additional factors that are beyond our control, such as:
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Changes in global supply and demand for natural gas and oil;
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commodity processing, gathering and transportation availability;
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domestic and global political and economic conditions;
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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
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Weather conditions, including hurricanes;
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technological advances affecting energy consumption;
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domestic and foreign governmental regulations; and
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the price and availability of alternative fuels.
Additionally, oil and natural gas prices do not necessarily move together.
Lower natural gas and oil prices may not only decrease our revenue on a per share basis, but also may reduce the amount of natural gas and oil that we can produce economically. This reduction may result in our having to make substantial downward adjustments to our estimated proved reserves. For example, during 2006, the previous oil and gas reserves quantities decreased by approximately 63% primarily due to the decrease in oil and gas prices from $59.87 per barrel and $8.01 per mcf at December 31, 2005 to $45.53 per barrel and $4.47 per mcf at December 31, 2006. The price per barrel of oil reflects our blend of oil and condensate. If the estimated capital investment based on recent historical data to drill and complete wells in this area is not reduced materially or if the prices for oil and gas decrease materially from year end 2007 prices we will be unable to economically develop most of our acreage.
All of our natural gas production is currently located in, and all of our future natural gas production is anticipated to be located in, the Rocky Mountain Region of the United States. The gas prices that we and other operators in the Rocky Mountain region have received and are currently receiving are at a discount to gas prices in other parts of the country. Factors that can cause price volatility for crude oil and natural gas within this region are:
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the availability of gathering systems with sufficient capacity to handle local production;
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seasonal fluctuations in local demand for production;
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local and national gas storage capacity;
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interstate pipeline capacity; and
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the availability and cost of gas transportation facilities from the Rocky Mountain region.
It is impossible to predict natural gas and oil price movements with certainty. A substantial or extended decline in natural gas and oil prices would materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.
Pipeline constraints may limit Gasco’s ability to sell its gas production and may negatively affect the price at which Gasco sells its gas.
Gasco’s production is transported through a single interstate pipeline. Any constraints on the capacity of this pipeline could adversely affect its ability to sell Gasco’s production and, in certain circumstances, may limit Gasco’s ability to sell any or all of its natural gas production in a given period. Pipeline capacity constraint could also lead to heightened price competition on such pipeline, which would reduce the price at which Gasco is able to sell the gas that does flow. During the second half of 2007, Gasco curtailed a portion of its natural gas production due to the low price for natural gas that prevailed in the Rockies. These low prices were due in part to gas-on-gas sales competition resulting from the region’s capacity to produce natural gas exceeding the take-away capacity of interstate pipelines that move the natural gas to other consuming regions in the United States. A reduction in the amount of natural gas that Gasco can sell or the price at which such natural gas can be sold could materially adversely affect Gasco’s financial position and results of operations.
Our oil and gas reserve information is estimated and may not reflect our actual reserves.
Estimating accumulations of gas and oil is complex and inexact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:
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the quality and quantity of available data;
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the interpretation of that data;
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the accuracy of various mandated economic assumptions; and
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the judgment of the persons preparing the estimate.
The most accurate method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data. The accuracy of the decline analysis method generally increases with the length of the production history. Since most of our wells had been producing less than seven years as of December 31, 2007, their production history was relatively short, so other (generally less accurate) methods such as volumetric analysis and analogy to the production history of wells of other operators in the same reservoir were used in conjunction with the decline analysis method to determine our estimates of proved reserves as of December 31, 2007. As our wells are produced over time and more data is available, the estimated proved reserves will be redetermined on an annual basis and may be adjusted based on that data. These adjustments could result in downward revisions of our reserve estimates. For example, we revised our reserves downward by 36% and 32% during the years ended December 31, 2006 and 2005, respectively.
Actual future production, gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development and prevailing gas and oil prices. Our reserves may also be susceptible to drainage by operators on adjacent properties.
It should not be assumed that the present value of future net cash flows included herein is the current market value of our estimated proved gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.
Future changes in commodity prices or our estimates and operational developments may result in impairment charges.
We may be required to write down the carrying value of our gas and oil properties when gas and oil prices are low or if there are substantial downward adjustments to the estimated proved reserves, increases in the estimates of development costs or deterioration in the exploration results.
We follow the full cost method of accounting under which capitalized gas and oil property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved gas and oil reserves less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value, if lower of unproved properties and the costs of any property not being amortized.
Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net revenues is computed by applying current prices of gas and oil to estimated future production of proved gas and oil reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions. Once an impairment of gas and oil properties is recognized, it is not reversible at a later date even if oil or gas prices increase. As of September 30, 2007, oil and gas prices were $62.29 per barrel and $0.345 per mcf. Our oil and gas reserves became uneconomic as the gas price on September 30, 2007 was less than our gathering costs to transport the gas to a sales point and would have resulted in an impairment of $65,620,000. However, subsequent to quarter end, oil and gas prices increased and, using these prices, our full cost pool would have exceeded the above-described ceiling by $32,790,000. Additionally, as of June 30, 2007, based on oil and gas prices of $54.09 per barrel and $3.90 per mcf, the full cost pool exceeded the above-described ceiling by $66,700,000. Subsequent to that quarter end, oil and gas prices increases reduced our impairment to $64,300,000. Therefore, impairment expense of $97,090,000 was recorded during the year ended December 31, 2007.
The development of oil and gas properties involves substantial risks that may materially and adversely affect us.
The business of exploring for and producing oil and gas involves a substantial risk of investment loss that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Drilling oil and gas wells involves the risk that the wells will be unproductive or that, although productive, the wells do not produce oil and/or gas in economic quantities. Other hazards, such as unusual or unexpected geological formations, pressures, fires, blowouts, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well. Adverse weather conditions can also hinder drilling operations.
A productive well may become uneconomic in the event water or other deleterious substances are encountered, which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances.
If we experience any one or more of these risks, our business, financial condition and results of operations could be materially and adversely affected.
We may not be able to obtain adequate financing to continue our operations.
We have relied in the past primarily on the sale of equity capital, the issuance of equity and farm-out and other similar types of transactions to fund working capital and the acquisition of our prospects and related leases. Failure to generate operating cash flow or to obtain additional financing could result in substantial dilution of our property interests, or delay or cause indefinite postponement of further exploration and development of our prospects with the possible loss of our properties.
We will require significant additional capital to fund our future activities and to service current and any future indebtedness. In particular, we face uncertainties relating to our ability to generate sufficient cash flows from operations to fund the level of capital expenditures required for our oil and gas exploration and production activities and our obligations under various agreements with third parties relating to exploration and development of certain prospects. Our failure to find the financial resources necessary to fund our planned activities and service our debt and other obligations could materially and adversely affect our business, financial condition and results of operations.
Delays in obtaining drilling permits could have a materially adverse effect on our ability to develop our properties in a timely manner.
The average processing time at the Bureau of Land Management in Vernal, Utah for an application to drill on federal leases has been increasing and currently is approximately 12 months. Approximately 82% of our gross acreage in Utah is located on federal leases. If we are delayed in procuring sufficient drilling permits for our federal properties, we may shift more of our drilling in Utah to our state leases, the permits for which require an average processing time of approximately two months. While such a shift in resources would not necessarily affect the rate of growth of our cash flow, it would result in a slower growth rate of our total proved reserves, because a higher percentage of the wells drilled on the state leases would be drilled on leases to which proved undeveloped reserves may already have been attributed.
We may have difficulty managing growth in our business.
Because of our small size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of experienced managers, geoscientists and engineers, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.
We compete with larger companies in acquiring properties and operating and drilling services.
Our natural gas and petroleum exploration activities take place in a highly competitive and speculative business atmosphere. In seeking suitable natural gas and petroleum properties for acquisition, we compete with a number of other companies operating in our areas of interest, including large oil and gas companies and other independent operators with greater financial and other resources. We do not believe that our competitive position in the petroleum and natural gas industry is significant.
There is a competitive market for obtaining drilling rigs and services and the manpower to operate them. The current high level of drilling activity in our areas of exploration may have a significant adverse impact on the timing and profitability of our operations. In addition, we are required to obtain drilling and right of way permits for our wells, and there is no assurance that such permits will be available on a timely basis or at all.
We may suffer losses or incur liability for events that we have, or that the operator of a property has, chosen not to insure against.
Insurance against every operational risk is not available at economic rates. We may suffer losses from uninsurable hazards that from hazards that we have or the operator thereof has, chosen not to insure against because of high premium costs or other reasons. We may become subject to liability for pollution, fire, explosion, blowouts, cratering and oil spills against which we cannot insure or against which we may elect not to insure. Such events could result in substantial damage to oil and gas wells, producing facilities and other property and personal injury. The payment of any such liabilities may have a material adverse effect on our business, financial condition and results of operations.
We may incur losses as a result of title deficiencies in the properties in which we invest.
If an examination of the title history of a property that we have purchased reveals a petroleum and natural gas lease that has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such petroleum and natural gas lease or leases would be lost.
It is our practice, in acquiring petroleum and natural gas leases, or undivided interests in petroleum and natural gas leases, not to undergo the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease. Rather, we will rely upon the judgment of petroleum and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.
If there are any title defects in the properties in which we hold an interest, we may suffer a monetary loss, including as a result of performing any necessary curative work prior to the drilling of a petroleum and natural gas well.
Our ability to market the oil and gas that we produce is essential to our business.
Several factors beyond our control may adversely affect our ability to market the oil and gas that we discover. These factors include the proximity, capacity and availability of oil and gas pipelines and processing equipment, market fluctuations of prices, taxes, royalties, land tenure, allowable production and environmental protection. The extent of these factors cannot be accurately predicted, but any one or a combination of these factors may result in our inability to sell our oil and gas at prices that would result in an adequate return on our invested capital. For example, we currently distribute the gas that we produce through a single pipeline. If this pipeline were to become unavailable, we would incur additional costs to secure a substitute facility in order to deliver the gas that we produce. In addition, although we currently have access to firm transportation for the majority of our current gas production, there is no assurance that we will be able to procure additional transportation on terms satisfactory to us, or at all, if we increase our production through our drilling program or acquisitions.
Environmental costs and liabilities and changing environmental regulation could materially affect our cash flow.
Our operations are subject to stringent federal, state and local laws and regulations relating to environmental protection. These laws and regulations may require the acquisition of permits or other governmental approvals, limit or prohibit our operations on environmentally sensitive lands, and place burdensome restrictions on the management and disposal of wastes. Failure to comply with these laws may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that may delay or prevent our operations. Any stringent changes to these environmental laws and regulations may result in increased costs to us with respect to the disposal of wastes, the performance of remedial activities, and the incurrence of capital expenditures. Please read “Item 1 -Business - Governmental Regulations and Environmental Laws” above.
We are subject to complex governmental regulations which may adversely affect the cost of our business.
Petroleum and natural gas exploration, development and production are subject to various types of regulation by local, state and federal agencies. We may be required to make large expenditures to comply with these regulatory requirements. Legislation affecting the petroleum and natural gas industry is under constant review for amendment and expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the petroleum and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Any increases in the regulatory burden on the petroleum and natural gas industry created by new legislation would increase our cost of doing business and adversely affect our profitability.
Our competitors may have greater resources which could enable them to pay a higher price for properties and to better withstand periods of low market prices for hydrocarbons.
The petroleum and natural gas industry is intensely competitive, and we compete with other companies with greater resources. Many of these companies not only explore for and produce crude petroleum and natural gas but also carry on refining operations and market petroleum and
other products on a regional, national or worldwide basis. Such companies may be able to pay more for productive petroleum and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may have a greater ability to continue exploration activities during periods of low hydrocarbon market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
Because our reserves and production are concentrated in a small number of properties, production problems or significant changes in reserve estimates related to any property could have a material impact on our business.
Our current reserves and production primarily come from a small number of producing properties in Utah. If mechanical problems with the wells or production facilities (including salt water disposal, pipelines, compressors and processing plants), depletion, weather or other events adversely affect any particular property, we could experience a significant decline in our production, which could have a material adverse effect on our cash flows, financial condition and results of operations. In addition, if the actual reserves associated with any one of our properties are less than estimated, our overall reserve estimates could be materially and adversely affected.
Our operations may be interrupted by severe weather or drilling restrictions.
Our operations are conducted in the Rocky Mountain region of the United States. The weather in this area can be extreme and can cause interruption in our exploration and production operations. Severe weather can result in damage to our facilities entailing longer operational interruptions and significant capital investment. Additionally, our operations are subject to disruption from winter storms and severe cold, which can limit operations involving fluids and impair access to our facilities.
Financial difficulties encountered by our partners or third-party operators could adversely affect the exploration and development of our prospects.
Liquidity and cash flow problems encountered by our partners or the co-owners of our properties may prevent or delay the drilling of a well or the development of a project. Our partners and working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farm-out partner being unwilling or unable to share such costs, we would have to find a new farm-out partner or obtain alternative funding in order to complete the exploration and development of the prospects subject to the farm-out agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary to fund either of these contingencies or that we would be able to find a new farm-out partner. If any of these circumstances were to occur, our ability to explore and develop our prospects could be adversely affected, which could have a material adverse effect on our business, financial condition and results of operations.
Shortages of supplies, equipment and personnel may adversely affect our operations.
The natural gas and oil industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment and supplies may be substantially increased and their availability may be limited. In addition, the demand for, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in service increases. If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due to excessive costs or demand or otherwise, our ability to execute our exploration and development plans could be materially and adversely affected and, as a result, our business, financial condition and results of operations could be materially and adversely affected.
Hedging our production may result in losses.
In order to manage our exposure to price volatility in marketing our oil and natural gas, we enter into oil and natural gas price risk management arrangements for a portion of our expected production. Commodity price hedging may limit the prices we actually realize and therefore reduce oil and natural gas revenues in the future. The fair value of our oil and natural gas derivative instruments outstanding as of December 31, 2007 was a liability of approximately $344,000. We have also entered into derivative instruments for the years 2008 and 2009 as further described in “Item 7A - Quantitative and Qualitative Disclosures about Market Risk.” In addition, our commodity price risk management transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
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production is less than expected;
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the counterparty to the contract defaults on its obligations; or
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there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.
In addition, hedging may limit the benefit we would otherwise receive from increases in the prices of oil and gas.
Lower oil and natural gas prices could negatively impact our ability to borrow.
Our revolving bank credit facility limits our borrowings to the borrowing base less our total outstanding letters of credit issued under the facility. Currently our borrowing base is $40.0 million and our outstanding letter of credit sublimit is $10.0 million. The borrowing base is determined periodically at the discretion of the bank and is based in part on oil and natural gas prices. Additionally, our revolving bank credit facility contains covenants that require us to maintain (1) a current ratio (defined as current assets plus unused availability under the credit facility divided by current liabilities excluding the current portion of the credit facility), determined at the end of each quarter, of not less than 1:1; and (2) a ratio of senior debt to EBITDAX (as such term is defined in the revolving credit facility) for the most recent quarter multiplied by four not to be greater than 3.5:1 for each fiscal quarter. In addition, the credit
facility contains covenants that restrict our ability to incur other indebtedness, create liens or sell our assets, pay dividends on our common stock and make certain investments. Lower oil and natural gas prices in the future could reduce our consolidated EBITDAX and thus could reduce our ability to incur additional indebtedness. Please read “Item 7 - Managements’ Discussion and Analysis of Financial Position and Results of Operations - Credit Agreement.”
Our revolving bank credit facility imposes restrictions on us that may affect our ability to successfully operate our business.
Our revolving bank credit facility imposes certain operational and financial restrictions on us that limit our ability to:
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incur additional indebtedness;
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create liens;
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sell our assets to, or consolidate or merge with or into, other companies;
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make investments and other restricted payments, including dividends; and
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engage in transactions with affiliates.
These limitations are subject to a number of important qualifications and exceptions. In addition, our revolving bank credit facility requires us to maintain certain financial ratios to satisfy certain financial conditions. These restrictions could also limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. Our revolving bank credit facility and restrictions there under are described in greater detail in “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Credit Facility.”
Our success depends on our key management personnel, the loss of any of whom could disrupt our business.
The success of our operations and activities is dependent to a significant extent on the efforts and abilities of our management. The loss of services of any of our key managers - including Mr. Erickson, our Chief Executive Officer; Mr. Decker, our Executive Vice President and Chief Operating Officer; and Mr. Grant, our Executive Vice President and Chief Financial Officer - could have a material adverse effect on our business. We have not obtained “key man” insurance for any of our management.
Our officers and directors are engaged in other businesses which may result in conflicts of interest.
Certain of Gasco’s officers and directors also serve as directors of other companies or have significant shareholdings in other companies operating in the oil and gas industry. Gasco’s chairman, Marc A. Bruner, is the largest shareholder of Galaxy Energy Corporation (“Galaxy”) and Exxcel Energy. Mr. Bruner also serves as the Chairman and Chief Operating Officer of Falcon Oil and Gas, Ltd. (“Falcon”). Falcon’s current drilling activities include projects in
Romania and Hungary. Carl Stadelhofer, one of Gasco’s directors is a director of Falcon. In addition, another Gasco director, C. Tony Lotito, currently serves as the Executive Vice President and a member of the Board of Directors of PetroHunter Corporation (“PetroHunter”), which is majority owned by Mr. Bruner. Charles Crowell, one of Gasco’s directors, is the Chief Executive Officer and President and serves as the Chairman of the Board of Directors of PetroHunter. Mr. Crowell also serves on the Boards of Directors of Providence Resources, Inc. Richard S. Langdon, another one of Gasco’s directors, is President and Chief Executive Officer of Matris Exploration Company, L.P., a private exploration and production company active in onshore California. Mr. Langdon is also a member of the Board of Directors of Constellation Energy Partners LLC (“CEP”), a public limited liability company focused on the acquisition, development and exploitation of oil and natural gas properties and related midstream assets. CEP’s activities are currently focused in the Black Warrior Basin of Alabama. Gasco estimates that all of its directors spend approximately 10% of their time on Gasco business. Mr. Erickson has direct private investments in certain Rocky Mountain and Mid-Continent oil and gas leases and has a majority interest in a private oil and gas company with core assets in Oklahoma and additional lease holdings in Colorado, Wyoming, North Dakota and Utah. Mr. Erickson is also a co-majority shareholder in a private company engaged in the exploration of non-oil and gas mineral resources in the Republic of Guinea, Africa. Mr. Erickson spends 100% of his time on Gasco business.
To the extent that such other companies participate in ventures in which Gasco may participate, or compete for prospects or financial resources with it, these officers and directors will have a conflict of interest in negotiating and concluding terms relating to the extent of such participation. In the event that such a conflict of interest arises at a meeting of the board of directors, a director who has such a conflict must disclose the nature and extent of his interest to the board of directors and abstain from voting for or against the approval of such participation or such terms.
In accordance with the laws of the State of Nevada, Gasco’s directors are required to act honestly and in good faith with a view to the best interests of Gasco. In determining whether or not Gasco will participate in a particular program and the interest therein to be acquired by it, the directors will primarily consider the degree of risk to which Gasco may be exposed and its financial position at that time.
It may be difficult to enforce judgments predicated on the federal securities laws on some of our board members who are not U.S. residents.
Two of our directors reside outside the United States and maintain a substantial portion of their assets outside the United States. As a result it may be difficult or impossible to effect service of process within the United States upon such persons, to bring suit in the United States against such persons or to enforce, in the U.S. courts, any judgment obtained there against such persons predicated upon any civil liability provisions of the U.S. federal securities laws.
Foreign courts may not entertain original actions against our directors or officers predicated solely upon U.S. federal securities laws. Furthermore, judgments predicated upon any civil liability provisions of the U.S. federal securities laws may not be directly enforceable in foreign countries.
Risks Related to Our Capital Stock
Our common stock has experienced, and may continue to experience, price volatility and a low trading volume.
The trading price of our common stock has been and may continue to be subject to large fluctuations, which may result in losses to investors. Our stock price may increase or decrease in response to a number of events and factors, including:
•
the results of our exploratory drilling;
•
trends in our industry and the markets in which we operate;
•
changes in the market price of the commodities we sell;
•
changes in financial estimates and recommendations by securities analysts;
•
acquisitions and financings;
•
quarterly variations in operating results;
•
the operating and stock price performance of other companies that investors may deem comparable to us; and
•
issuances, purchases or sales of blocks of our common stock.
This volatility may adversely affect the price of our common stock regardless of our operating performance. See “Item 5 - Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for further discussion.
Shares eligible for future sale may cause the market price for our common stock to drop significantly, even if our business is doing well.
If our existing shareholders sell our common stock in the market, or if there is a perception that significant sales may occur, the market price of our common stock could drop significantly. In such case, our ability to raise additional capital in the financial markets at a time and price favorable to us might be impaired. In addition, our board of directors has the authority to issue additional shares of our authorized but unissued common stock without the approval of our shareholders, subject to certain limitations under the rules of the exchange on which our common stock is listed. Additional issuances of our common stock would dilute the ownership percentage of existing shareholders and may dilute the earnings per share of our common stock. As of December 31, 2007, we had 107,216,771 shares of common stock issued and outstanding and outstanding options to purchase an additional 10,729,138 shares of common stock. Additional options may be granted to purchase 2,843,539 shares of common stock under our stock option plan and an additional 268,850 shares of common stock are issuable under our restricted stock plan. As of December 31 of each year, the number of shares of common stock issuable under our stock option plan automatically increases so that the total number of shares of
common stock issuable under such plan is equal to 10% of the total number of shares of common stock outstanding on such date.
Assuming all of our outstanding 5.50% Convertible Senior Notes due 2011 are converted at the applicable conversion prices, the number of shares of our common stock outstanding would increase by approximately 16,250,000 shares to approximately 123,466,771 shares (this number assumes no exercise of the options described above and no additional grants of options or restricted stock).
We have not previously paid dividends on our common stock and we do not anticipate doing so in the foreseeable future.
We have not in the past paid, and do not anticipate paying in the foreseeable future, cash dividends on our common stock. Our outstanding revolving bank credit agreement contains covenants that restrict our ability to pay dividends on our common stock. Additionally, any future decision to pay a dividend and the amount of any dividend paid, if permitted, will be made at the discretion of our board of directors.
We have anti-takeover provisions in our certificate of incorporation and by-laws that may discourage a change of control.
Our articles of incorporation and bylaws contain several provisions that could delay or make more difficult the acquisition of us through a hostile tender offer, open market purchases, proxy contest, merger or other takeover attempt that a stockholder might consider in his or her best interest, including those attempts that might result in a premium over the market price of our common stock.
Under the terms of our articles of incorporation and as permitted under Nevada law, we have elected not to be subject to Nevada’s anti-takeover law. This law provides that specified persons who, together with affiliates and associates, own, or within three years did own, 15% or more of the outstanding voting stock of a corporation cannot engage in specified business combinations with the corporation for a period of three years after the date on which the person became an interested stockholder. With the approval of our stockholders, we may amend our articles of incorporation in the future to become subject to the anti-takeover law. This provision would then have an anti-takeover effect for transactions not approved in advance by our board of directors, including discouraging takeover attempts that a stockholder might consider in his or her best interest or that might result in a premium over the market price for the shares of our common stock.
ITEM 1 B.
ITEM 1 B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2
ITEM 2 - PROPERTIES
Petroleum and Natural Gas Properties
Riverbend Project
The Riverbend Project comprises approximately 124,547 gross acres in the Uinta Basin of northeastern Utah, of which we hold interests in approximately 92,463 net acres as of December 31, 2007. Historically, our engineering and geologic focus has been concentrated on three tight-sand formations in the Uinta basin: the Wasatch, Mesaverde and Blackhawk formations. A typical well drilled into these formations may encounter multiple distinct natural gas sands located between approximately 6,000 and 13,000 feet in depth that are completed using up to ten staged fracs. During the second quarter of 2007, we spudded our first Mancos Shale test well and since then we have drilled and completed three wells in the Mancos Shale. We are currently completing another well and are awaiting completion on another three. We continue to focus on reducing our drilling days to improve well economics. The current target is 20 to 25 days to drill from below surface casing to the Upper Mancos interval between 13,000 feet and 15,000 feet. The fastest Mancos well was drilled to 14,250 feet in 16 days. Our current plan is for all wells in the Riverbend Project to be drilled to the Upper Mancos during 2008.
During 2007, we spudded 25 gross operated wells (9.6 net) and reached total depth on 28 gross operated wells (10.9 net). We also participated in one (0.25 net) outside operated well that was spud and reached total depth during 2007. Initial completion operations were conducted on 23 operated wells (10.1 net) and one operated well bore was re-entered to complete behind-pipe pay. We also participated in the completion of one outside operated well (0.25 net) during 2007. As of December 31, 2007, we operated 107 gross producing wells and currently have an inventory of five operated wells awaiting initial completion and 37 wells awaiting uphole completions. We currently have two drilling rigs under contract, one through April 2010 and the other on a well-by-well basis.
On August 1, 2007, Gasco entered into a definitive agreement with a subsidiary of NFR whereby the subsidiary of NFR will participate in a 30-well drilling program in Gasco’s Riverbend Project through the second quarter of 2008. The terms of the agreement allow for NFR to earn two-thirds of Gasco’s interest in each 40-acre drilling location, 100 feet below total depth drilled, in exchange for paying its share of costs, including a per-well location fee paid to Gasco as the operator of the project. The agreement covers substantially all of Gasco’s 2007 drilling program, retroactive for wells drilled year-to-date, and as such includes 13 gross operated wells spudded (3.5 net to Gasco’s interest and 6.9 net to NFR) in 2007. At signing, Gasco received cash consideration of $19,031,602 for NFR’s share of the wells that had been drilled, expected to be drilled and completed or spud prior to agreement date.
The general terms of the agreement are as follows:
•
The agreement consists of Gasco’s leasehold position in portions of Uintah County, Utah and does not include assets in California, Nevada or Wyoming.
•
The drilling program targets Wasatch, Mesaverde, Blackhawk and Upper Mancos formations.
•
Gasco can continue to independently develop its acreage.
Upon completion of the initial 30-well program, NFR will have earned approximately 67% of Gasco’s interest in 1,200 gross acres in the Riverbend Project.
On December 14, 2007, we closed the previously announced purchase of Brek. As a result of the Brek Acquisition, Gasco acquired approximately 17,000 net acres in the Uinta Basin of Utah, approximately 7,200 net acres in the Green River Basin of Wyoming and additional working interests in ten producing properties in which Gasco was already the operator and holds working interests. The acquisition is expected to simplify Gasco’s acreage portfolio by absorbing a working interest partner that previously owned approximately 14% of Gasco’s undeveloped acreage in Utah and Wyoming. Gasco does not expect to incur any additional overhead expenses as a result of the acquisition.
Under the terms of the Brek Acquisition, a wholly-owned subsidiary of Gasco merged with and into Brek. As part of the transaction, Brek’s President and CEO, who owned approximately 18% of the outstanding common stock of Brek, agreed to deposit 550,000 shares of Gasco common stock acquired in the transaction in escrow to satisfy any claims with respect to breaches of representations and warranties of Brek for a period of one year following the merger.
In connection with the acquisition, Gasco issued 10,999,868 shares of its common stock to Brek’s shareholders. The shares of common stock issued to Brek shareholders were valued at $2.76 per share, which was the average value of the Company’s common stock for two days before and after the merger agreement was signed. The total purchase price of the Brek Acquisition was $30,749,300.
Gasco received approval of its Riverbend Environmental Assessment (“EA”) during 2006. The approved EA included 45 proposed wells and provided for accelerated permitting approvals from the Bureau of Land Management. As of March 3, 2008, we have drilled 40 of the 45 approved locations.
Greater Green River Basin Project
As of December 31, 2007, the Company has a leasehold interest in approximately 68,188 gross (41,372 net) acres in the Greater Green River Basin area of Wyoming. The acreage covers two prospects identified by Gasco.
During the second quarter of 2007, management believed that the low natural gas prices received in the Rockies caused the potential resources related to our Wyoming acreage to become uneconomic. During 2006, we began drilling a well in the Muddy Creek Prospect in Wyoming to test natural gas potential in two formations to a proposed depth of 14,400 feet. Intermediate casing was set at approximately 9,600 feet when drilling operations were suspended due to winter lease stipulations. The low natural gas prices in this area made it difficult for us to find a partner to participate in the drilling of this well and as a result, management revised its original plans for this well and no longer planned to recommence drilling operations on this well. Therefore the total well costs of approximately $3,925,000 were reclassified from wells in progress into proved property during the second quarter of 2007. Additionally, approximately
$6,230,000 of unproved leasehold costs related to our Wyoming acreage was reclassified to proved property during the second quarter of 2007. Both of these amounts, totaling $10,155,000, were included in the ceiling test and depletion calculations.
We continue to pursue many options for this area such as farm-outs, acreage sales and partners to participate in any future drilling projects in this area.
Southern California Project
The Company has a leasehold interest in approximately 16,336 gross acres (13,089 net acres) in Kern and San Luis Obispo Counties of Southern California. We continue to pay leasehold rentals and geological expenses to preserve our acreage positions and are marketing these prospects to attract drilling partners for the development of this area.
Nevada Project
The Company has a leasehold interest in approximately 87,803 gross (41,893 net acres) in nine prospects within White Pine and Elko Counties Nevada. We have farmed out our acreage to an industry partner for the development of these prospects. Under the terms of the agreement, the industry partner has the right to earn up to 80% of the Company’s interest in these properties. Two wells were drilled in this area during 2007, both were dry holes.
Company Reserve Estimates
The tables below set forth information as of December 31, 2007 with respect to our estimated proved reserves, the associated present value of discounted future net cash flows and the standardized measure of discounted future net cash flows. Neither the pre-tax present value of discounted future net cash flows nor the after-tax standardized measure is intended to represent the current market value of the estimated oil and natural gas reserves we own. All of the Company’s proved reserves are located within the state of Utah.
(a)
Present value of discounted future net cash flows represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at December 31, 2007. The prices used in the reserve report prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers, were of $6.53 per Mcf of gas and $73.95 per bbl of oil. These prices should not be
interpreted as a prediction of future prices. Present value of discounted future net cash flows differs from the standardized measure of future net cash flows only because the former does not include the effects of estimated future income tax expenses ($2.38 million as of December 31, 2007).
Management uses discounted future net cash flows, which is calculated without deducting estimated future income tax expenses, and the present value thereof as one measure of the value of the Company’s current proved reserves and to compare relative values among peer companies without regard to income taxes. We also understand that securities analysts and rating agencies use this measure in similar ways. While future net revenue and present value are based on prices, costs and discount factors which are consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company.
(b)
The standardized measure of discounted future net cash flows is calculated in accordance with SFAS 69. Additional information on the standardized measure is presented in Note 17 of the notes to our consolidated financial statements included in Item 8 of this report.
Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. An increase/decrease in price of $0.10 per Mcf for natural gas and $1.00 per barrel of oil from the actual December 31, 2007 prices would result in an increase/decrease in the Company’s December 31, 2007 present value of discounted future net cash flows of approximately $5,458,600.
No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the Securities and Exchange Commission.
Volumes, Prices and Operating Expenses
The following table presents information regarding the production volumes, average sales prices received and average production costs associated with the Company’s sales of natural gas and oil for the periods indicated.
Development, Exploration and Acquisition Capital Expenditures
During the years ended December 31, 2007, 2006 and 2005, we incurred $82,496,756, $87,270,883 and $50,069,968 in development and exploration activities, respectively. During 2007, we completed the Brek Acquisition, as described previously, and as a result acquired approximately 17,000 net acres in the Uinta Basin of Utah, approximately 7,200 net acres in the Green River Basin of Wyoming and additional working interests in ten producing properties in which Gasco was already the operator and holds working interests. We also entered in to a 30-well drilling program in our Riverbend Project through the second quarter of 2008, as discussed previously. The terms of the agreement allow for NFR to earn two-thirds of our interest in each 40-acre drilling location, 100 feet below total depth drilled, in exchange for paying its share of costs, including a per-well location fee paid to Gasco as the operator of the project. During 2006, we completed a property acquisition of approximately 21 miles of mainline gathering pipelines and working interests in 24 oil and gas wells in the Uinta Basin of Utah for $4,875,000. During 2005 we purchased a drilling rig for approximately $5,000,000. As of December 31, 2007, the Company operated 107 gross (69.7 net to Gasco’s interest) producing gas wells and 5 gross (5.0 net) shut-in gas wells located on these properties.
The following table presents information regarding the Company’s net costs incurred in the purchase of proved and unproved properties and in exploration and development activities:
Productive Gas Wells
The following summarizes the Company’s productive and shut-in gas wells as of December 31, 2007. Productive wells are producing wells and wells capable of production. Shut-in wells are wells that are capable of production but are currently not producing. Gross wells are the total number of wells in which the Company has an interest. Net wells are the sum of the Company’s fractional interests owned in the gross wells.
The Company operates 107 of the above producing wells and all of the shut-in wells.
Oil and Gas Acreage
The following table sets forth the undeveloped and developed leasehold acreage, by area, held by the Company as of December 31, 2007. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. Developed acres are acres which are spaced or assignable to productive wells. Gross acres are the total number of acres in which Gasco has a working interest. Net acres are the sum of Gasco’s fractional interests owned in the gross acres. The table does not include acreage that the Company has a contractual right to acquire or to earn through drilling projects, or any other acreage for which the Company has not yet received leasehold assignments. In certain leases, the Company’s ownership is not the same for all depths; therefore, the net acres in these leases are calculated using the greatest ownership interest at any depth. Generally this greater interest represents Gasco’s ownership in the primary objective formation.
The following table summarizes the gross and net undeveloped acres by area that will expire in each of the next three years. The Company’s acreage positions are maintained by the payment of delay rentals or by the existence of a producing well on the acreage.
As of December 31, 2007, approximately 82% of the gross acreage that Gasco holds is located on federal lands and approximately 17% of the acreage is located on state lands. It has been Gasco’s experience that the permitting process related to the development of acreage on federal lands is more time consuming and expensive than the permitting process related to acreage on state lands. The Company has generally been able to obtain state permits within 60 days, while obtaining federal permits has taken approximately 12 months or longer. If we are delayed in procuring sufficient drilling permits for our federal properties, we will shift more of our drilling in Utah to our state leases. While such a shift in resources would not necessarily affect the rate of growth of our cash flow, it would result in a slower growth rate of our total proved reserves, because a higher percentage of the wells drilled on the state leases will be drilled on leases to which proved undeveloped reserves may already have been attributed. Additionally, if the development of the Company’s acreage located on federal lands is delayed significantly by the permitting process, the Company may have to operate at a loss for an extended period of time.
Drilling Activity
The following table sets forth the Company’s drilling activity during the years ended December 31, 2007, 2006 and 2005. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by the Company’s working interest.
Office Space
The Company leases approximately 9,880 square feet of office space in Englewood, Colorado, under a lease, which terminates on May 31, 2010. The average rent for this space over the life of the lease is approximately $140,800 per year.
ITEM 3
ITEM 3 - LEGAL PROCEEDINGS
In early 2007, a consultant to Riverbend Gas Gathering, LLC (“Riverbend”), a wholly owned subsidiary of the Company, that was preparing air emission calculations for possible future capacity expansions, preliminarily determined that Riverbend may have not accurately calculated the amount of air pollutants that could be emitted from certain existing equipment at its Riverbend Compressor Station in Uintah County, Utah. Riverbend thereafter undertook a more detailed assessment, which confirmed that it had not obtained certain air permits nor complied with certain air pollution regulatory programs that were applicable to its operations at the Riverbend Compressor Station. On June 22, 2007, Riverbend sent a letter to the United States Environmental Protection Agency (the “EPA”) Region 8 office in Denver, Colorado, which-because the Riverbend Compressor Station is located in Indian Country-is the agency that has jurisdiction over federal air permitting and air pollution regulatory programs. The letter voluntarily disclosed the potential violations to the EPA and informed the agency of the steps that Riverbend had taken and planned to take to achieve compliance. In November 2007, Riverbend met with EPA Region 8 personnel and discussed the disclosed violations, its plans to bring the Riverbend Compressor Station into compliance, and possible resolution of the disclosed violations. In a letter to the EPA dated January 23, 2008, Riverbend confirmed its willingness to sign a consent decree with the United States that resolves the apparent violations, specifies the appropriate corrective action, provides a schedule for Riverbend to achieve such corrective action, and includes a covenant not to sue that will effectively authorize Riverbend to continue its operations, including certain capacity expansions, while the specified corrective action is being implemented. Riverbend anticipates that such a resolution will be achieved during 2008. Riverbend believes that all necessary pollution control and other equipment likely to be required by such a resolution is already installed at the site or accounted for in the Company’s capital budget, and that any civil penalties that may be assessed will not materially affect the Company’s financial position.
Riverbend’s emission review also included the Gate Canyon Compressor Station, which is a small compressor station operated by Riverbend that is located on land over which the State of Utah has regulatory jurisdiction. As a result of this review, Riverbend determined that its application for minor new source review authorization from the Utah Department of Environmental Quality (“UDEQ”) for the Gate Canyon Compressor Station did not include a dehydrator that had been installed at the site. Riverbend has submitted an application to UDEQ to revise the existing minor new source review authorization to include this equipment. If any penalties are sought by the State of Utah for not having included the equipment in the original application for a minor new source review authorization, the Company anticipates that they would not materially affect the Company’s financial position.
ITEM 4
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5
ITEM 5 - MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The Company’s common stock is traded on the American Stock Exchange under the symbol “GSX.” As of March 3, 2008, the Company had 323 record shareholders of its common stock. During the last two fiscal years, no cash dividends were declared on Gasco’s common stock. The Company’s management does not anticipate that dividends will be paid on its common stock in the near future as Gasco’s revolving bank credit facility further discussed in “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operation - Credit Facility”, contains covenants that restrict the payment of dividends.
The following table sets forth, for the periods indicated, the high and low sales prices per share of the Company’s common stock as reported on the American Stock Exchange for the periods reflected.
Securities Authorized for Issuance under Equity Compensation Plans
See “Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” regarding information about the Company’s equity compensation plans.
ITEM 6
ITEM 6 - SELECTED FINANCIAL DATA
The following table sets forth selected financial data, derived from our historical consolidated financial statements and related notes, regarding Gasco’s financial position and results of operations as the dates indicated. The financial information is an integral part of, and should be read in conjunction with, the consolidated financial statements and notes thereto included in Item 8 hereof. Information concerning significant trends in financial condition and results of operations is contained in “Item 7
ITEM 7 - MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
Forward Looking Statements
Please refer to the section entitled “Cautionary Statement Regarding Forward Looking Statements” under Item 1 for a discussion of factors which could affect the outcome of forward looking statements used by the Company.
Overview
Gasco is a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon prospects, primarily in the Rocky Mountain region. The Company’s business strategy is to enhance shareholder value by using technologies new to a specific area to generate and develop high-potential exploitation resources in this area. Our principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to those leases. The operations of Brek are included in our results of operations for all periods subsequent to December 14, 2007. Our budget for our 2008 capital program reflects our commitment to build upon our historical successes and continue our efforts to demonstrate the economic viability of our resource in the Uinta Basin of Utah. Economic viability of this resource play is a function of the price of natural gas and oil, well investment, well operating cost and well performance. If we are unable to maintain the reduced capital investment based on recent historical data to drill and complete wells in this area, the estimated well performance based on recent historical performance data in this area is not increased materially or if the prices for oil and gas do not increase from the average prices received during 2007 prices we will be unable to economically develop most of our acreage in the Uinta Basin of Utah.
Our budget for our 2008 capital program is not contingent upon any material increases in the prices of oil and gas experienced throughout 2007. In 2008, we plan to continue to prove the geological model, delineate the resource and demonstrate additional operational efficiencies. Based on historical experience in 2007, we believe that we will be able to continue to demonstrate reduced well investment in 2008 through operating efficiencies gained through improved drilling and completion practices, introduction of new technologies and economies of scale. During 2007, we experienced reduced well investment due to reduced drilling days and lower service costs. We believe well performance is likely to improve as knowledge increases with additional well development and introduction of new technologies.
Drilling Activity
During 2007, we spudded 25 gross operated wells (9.6 net) and reached total depth on 28 gross operated wells (10.9 net). We also participated in one (0.25 net) outside operated well that was spud and reached total depth during 2007. Initial completion operations were conducted on 23 operated wells (10.1 net) and one operated well bore was re-entered to complete behind-pipe pay. We also participated in the completion of one outside operated well (0.25 net) during 2007. As of December 31, 2007, we operated 107 gross producing wells and currently have an inventory of five operated wells awaiting initial completion and 37 wells awaiting uphole completions. We currently have two drilling rigs under contract, one through April 2010 and the other on a well-by-well basis.
The following table summarizes our capital expenditures during 2007 by reconciling the cash paid for acquisitions, development and exploration included within the Consolidated Statement of Cash Flows in Item 8.
Forward Sales Contract
During April 2007, we entered into a sales and transportation agreement for 18,000 MMBTU per day, at the first of the month IFERC CIG index price, net of transportation, marketing and fuel expenses for our 2007 production. For our 2008 and 2009 production, we entered into a firm commitment to sell 30,000 MMBtu per day of our gross production from the Uinta Basin. During the first quarter of 2008, 18,000 MMBTU per day of such amount is contracted at the CIG first of month price and the remaining 12,000 MMBtu per day will be priced at the NW Rockies first of month price. Beginning in the second quarter of 2008, the entire contracted amount will be based on NW Rockies first of month price. We have elected the normal purchase and sale exemption under paragraph 10(b) of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” because we anticipate that (1) we will produce the volumes required to be delivered under the terms of the contract, (2) it is probable the delivery will be made to the counterparty and (3) the counterparty will fulfill its contractual obligations under the terms of the contracts. As such, we believe we are not required to treat the contract as a derivative and the contract will not be marked to market under the provisions of SFAS No. 133.
Derivatives
Our results of operations and operating cash flows are affected by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. As of December 31, 2007, natural gas derivative instruments were comprised of a swap agreement which we entered into during December 2007 for the calendar year 2008. The fair market value of the agreement was a liability of $343,759 as of December 31, 2007. During January and February 2008 we entered into additional swap and costless collar agreements for 2008 and 2009 production. These instruments allow us to predict with greater certainty the effective natural gas prices to be received for our hedged production. See further discussion in “Item 7A
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk
Our results of operations and operating cash flows are affected by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. As of December 31, 2007, natural gas derivative instruments consisted of a swap agreement which we entered into during December 2007 for the calendar year 2008. The fair market value of the agreement was a liability of $343,759 as of December 31, 2007. During January and February 2008 we entered into additional swap and costless collar agreements for 2008 and 2009 production. These instruments allow us to predict with greater certainty the effective natural gas prices to be received for our hedged production. Our derivative contracts are described below:
•
For our swap instruments, Gasco receives a fixed price for the hedged commodity and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.
•
Our costless collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Gasco receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.
Our swap agreements for 2008 and 2009 are summarized in the table below:
Our costless collar agreements for 2008 and 2009 are summarized in the table below:
(a)
Contract was initiated in December 2007 and is included in the accompanying financial statements as derivative instruments at fair market value as a liability of $343,759.
(b)
Northwest Pipeline Rocky Mountains - Inside FERC first of month index price.
We have established the fair value of our derivative instruments using estimates of fair value reported by our counterparty and subsequently evaluated internally using established index price and other sources. The actual contribution to our future results of operations will be based on the market prices at the time of settlement and may be more or less than the value estimates used at December 31, 2007. Our hedging contracts have no requirements for us to post additional collateral based upon the changes in the market value of our hedge instruments.
The swap contracts will allow us to predict with greater certainty the effective natural gas prices that we will receive for our hedged production and to benefit from operating cash flows when market prices are less than the fixed prices of the contracts. However, we will not benefit from market prices that are higher than the fixed prices in the contracts for the hedged production. The collar structures provide for participation in price increases and decreases to the extent of the ceiling and floors provided in our contracts.
Interest Rate Risk
We do not currently use interest rate derivatives to mitigate our exposure, including under our revolving bank credit facility, to the volatility in interest rates.
ITEM 8
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets at December 31, 2007 and 2006
58-59
Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2007, 2006 and 2005
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005
Notes to Consolidated Financial Statements
63-101
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Gasco Energy, Inc.
We have audited the consolidated balance sheets of Gasco Energy, Inc. and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 2007. These consolidated 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 consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Gasco Energy, Inc. and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Gasco Energy, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 29, 2008 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
As discussed in Note 3 to the accompanying consolidated financial statements, effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R), Share-Based Payment.
/s/ Hein & Associates LLP
HEIN & ASSOCIATES LLP
Denver, Colorado
February 29, 2008
GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of the consolidated financial statements.
GASCO ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (continued)
The accompanying notes are an integral part of the consolidated financial statements.
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of the consolidated financial statements.
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
The accompanying notes are an integral part of the consolidated financial statements.
GASCO ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of the consolidated financial statements.
GASCO ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005
NOTE 1 - ORGANIZATION
Gasco Energy, Inc. (“Gasco,” “the Company,” “we,” “our” or “us”) was incorporated under the laws of the State of Nevada on April 21, 1997 and operated as a “shell” company until December 31, 1999. Gasco is a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon resources, primarily in the Rocky Mountain region. Our principal business strategy is to enhance stockholder value by using technologies new to a specific area to generate and develop high-potential exploitation resources in this area. Our principal business is the acquisition of leasehold interests in petroleum and natural gas rights, either directly or indirectly, and the exploitation and development of properties subject to these leases. We are currently focusing our drilling efforts in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Wasatch, Mesaverde and Blackhawk, Mancos and Dakota/Morrison formations.
NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The accompanying consolidated financial statements include Gasco and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated.
Cash and Cash Equivalents
All highly liquid investments purchased with an initial maturity of three months or less are considered to be cash equivalents.
Restricted Investment
The restricted investment balance as of December 31, 2006 was comprised of $3,575,000 invested in U.S. government securities in an amount sufficient to provide for the payment of two semi-annual scheduled interest payments on the Company’s outstanding 5.5% Convertible Senior Notes (“Notes”), as further described in Note 8. The restricted investment was zero as of December 31, 2007 as the Company had paid all of the interest payments that were escrowed.
Short-term Investments
The Company’s short-term investments as of December 31, 2006 consisted primarily of preferred auction rate securities, which were classified as available-for-sale. Preferred auction rate securities represent preferred shares issued by closed end funds and are typically traded at auctions that are held periodically where the dividend rate for the next period is set. The Company invests in AAA/Aaa rated preferred auctions that have a dividend rate period of 28
days or less. These securities were stated at fair value based on quoted market prices. The income earned on these investments was included in interest income in the accompanying consolidated financial statements. These investments were sold during the first quarter of 2007.
Concentration of Credit Risk
The Company’s cash equivalents, short-term investments and derivative instruments are exposed to concentrations of credit risk. The Company manages and controls this risk by placing these funds and contracts with major financial institutions.
The Company’s receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, the collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized. However, to date the Company has had minimal bad debts.
Significant Customers
During the years ended December 31, 2007, 2006 and 2005, 80%, 94% and 96%, respectively, of the Company’s production was sold to one customer, ConocoPhillips Company. Approximately 79% of the accounts receivable - revenue as of December 31, 2007 is due from ConocoPhillips. However, Gasco does not believe that the loss of a single purchaser, including ConocoPhillips Company, would materially affect the Company’s business because there are numerous other purchasers in the areas in which Gasco sells its production.
Inventory
Inventory consists of pipe and tubular goods intended to be used in the Company’s oil and gas operations, and is stated at the lower of cost or market using the average cost valuation method.
Oil and Gas Properties
The Company follows the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center (“full cost pool”). Such costs include lease acquisition costs, geological and geophysical expenses, overhead directly related to exploration and development activities and costs of drilling both productive and non-productive wells. The Company capitalized $129,825, $353,190 and $260,227 of internal costs during the years ended December 31, 2007, 2006 and 2005, respectively. Costs associated with production and general corporate activities are expensed in the period incurred. Proceeds from property sales are generally credited to the full cost pool without gain or loss recognition unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to a cost center. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.
Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized
costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development costs to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. During 2007, approximately $6,230,000 of unproved lease costs related to our Wyoming acreage was reclassified to proved property and was included in the ceiling test and depletion calculations. During 2006, approximately $3,786,000 of unproved lease costs related to expiring acreage in Wyoming was also reclassified to proved property and was included in the ceiling test and depletion calculations. Management believes that the continued low natural gas prices received in the Rockies during 2007 have caused the potential resources related to our Wyoming acreage to become uneconomic.
Total well costs are transferred to the depletable pool even when multiple targeted zones have not been fully evaluated. For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil.
Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes (full cost pool) may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued in the balance sheet plus the cost, or estimated fair value, if lower of unproved properties and the costs of any properties not being amortized, if any. Should the full cost pool exceed this ceiling, an impairment is recognized. The present value of estimated future net revenues is computed by applying current oil and gas prices to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions. However, subsequent commodity price increases may be utilized to calculate the ceiling value.
During the second quarter of 2007, management believed that the low natural gas prices received in the Rockies caused the potential resources related to our Wyoming acreage to become uneconomic. During 2006, we began drilling a well in the Muddy Creek Prospect in Wyoming to test natural gas potential in two formations to a proposed depth of 14,400 feet. Intermediate casing was set at approximately 9,600 feet when drilling operations were suspended due to winter lease stipulations. Since it was our intention to continue drilling operations on this well in July 2007, this well was classified as a well in progress at December 31, 2006 and at March 31, 2007. The low natural gas prices in this area made it difficult for us to find a partner to participate in the drilling of this well and as a result, management revised its original plans for this well and no longer planned to recommence drilling operations on this well. Therefore, the total well costs of approximately $3,925,000 were reclassified from wells in progress into proved property during the second quarter of 2007. Both this amount and the acreage impairment described above totaling $10,155,000 were included in the ceiling test and depletion calculations.
As of September 30, 2007, oil and gas prices were $62.29 per barrel and $0.345 per mcf. Our oil and gas reserves became uneconomic as the gas price on September 30, 2007 was less than our gathering costs to transport the gas to a sales point and would have resulted in an impairment of $65,620,000. However, subsequent to quarter end, oil and gas prices increased; and using these prices our full cost pool would have exceeded the above described ceiling by $32,790,000. Additionally, as of June 30, 2007, based on oil and gas prices of $54.09 per barrel and $3.90 per mcf, the full cost pool exceeded the above described ceiling by $66,700,000. Subsequent to that quarter end, oil and gas prices increases reduced our impairment to $64,300,000. Therefore, impairment expense of $97,090,000 was recorded during the year ended December 31, 2007.
As of December 31, 2006, based on oil and gas prices of $4.47 per mcf and $45.53 per barrel, the full cost pool would have exceeded the above described ceiling by $28,500,000. However, subsequent to year end, oil and gas prices increased; and using these prices, the Company’s full cost pool would not have exceeded the ceiling limitation. As a result of the increase in the ceiling amount using subsequent prices, the Company did not record an impairment of its oil and gas prices at December 31, 2006. As of June 30, 2006, the Company’s full cost pool exceeded the ceiling limitation based on oil and gas prices of $59.87 per barrel and $5.42 per mcf. Subsequent commodity price increases were not sufficient to eliminate the need for the impairment and therefore, impairment expense of $51,000,000 was recorded during the year ended December 31, 2006.
Capitalized Interest
The Company capitalizes interest costs to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Interest costs capitalized in 2007 and 2006 were $548,047 and $231,500, respectively. No interest was capitalized during 2005.
Wells in Progress
Wells in progress at December 31, 2007 represent the costs associated with the drilling of one well in the Riverbend area of Utah. Since the well had not reached total depth as of December 31, 2007, it was classified as wells in progress and was withheld from the depletion calculation and the ceiling test. The costs for this well will be transferred into proved property when the well reaches total depth and is cased and will become subject to depletion and the ceiling test calculation in future periods. Wells in progress at December 31, 2006 represented the costs associated with the drilling of two wells in the Riverbend area of Utah and one well in the Greater Green River Basin in Wyoming. There costs were reclassified into proved properties during 2007 and became subject to the depletion calculation and the ceiling test.
Gathering Assets
Gathering assets are comprised of the costs associated with the construction of the Company’s pipeline and gathering system located in the Riverbend area of Utah. These assets are being depreciated on a units-of-production method based upon estimated proved oil and gas reserves of the wells that are expected to flow through the gathering system.
Facilities and Equipment
During 2006, the Company constructed two evaporation pits in the Riverbend area of Utah to be used for the disposal of produced water from the wells that Gasco operates in the area. The pits are being depreciated using the straight-line method over their estimated useful life of twenty-five years. The costs of water disposal into the evaporation pits is charged to wells operated by Gasco and therefore, net revenue attributable to the outside working interest owners from the evaporation pits of $206,186 and $179,766 was recorded as a credit to proved properties during 2007 and 2006, respectively.
The Company’s other oil and gas equipment is depreciated using the straight-line method over the estimated useful life of the equipment of five to ten years. The rental of the equipment owned by Gasco is charged to the wells that are operated by Gasco and therefore, net revenue attributable to the outside working interest owners from the rig and equipment rental of $887,080 and $748,690 was recorded as a credit to proved properties during 2007 and 2006, respectively.
Impairment of Long-lived Assets
The Company’s unproved properties are evaluated quarterly for the possibility of potential impairment. During 2007 approximately $6,230,000 of unproved lease costs related to our Wyoming acreage was reclassified to proved property and was included in the ceiling test and depletion calculations. During the year ended December 31, 2006 approximately $3,786,000 of unproved lease costs related primarily to expiring acreage in Wyoming was reclassified to proved property. Other than oil and gas properties, the Company has no other long-lived assets and to date has not recognized any impairment losses.
Deferred Financing Costs
Deferred financing costs include the costs associated with the Company’s issuance of $65,000,000 of Convertible Notes during October 2004, which are being amortized over the seven year life of the notes; and the debt issuance costs incurred in connection with the Company’s credit facility, which are being amortized over the four year term of the credit facility (see Note 7). The Company recorded amortization expense of $518,233, $503,216 and $458,167 related to these costs during the years ended December 31, 2007, 2006 and 2005, respectively.
Financial Instruments
The Company’s financial instruments including cash and cash equivalents, accounts receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity
of these instruments. The Company’s derivative instruments are recorded at fair market value, as discussed below. The Company’s borrowings under its credit facility, as further described in Note 7, approximates the fair value due to its floating rate structure. The Company’s Notes are recorded at cost, and the fair value is disclosed in Note 8. Since considerable judgment is required to develop estimates of fair value, the estimates provided are not necessarily indicative of the amounts the Company could realize upon the purchase or refinancing of such instruments.
Derivatives
The Company uses derivative instruments to provide a measure of stability to our cash flows in an environment of volatile oil and gas prices and to manage our exposure to commodity price risk. During December 2007, we entered into a natural gas swap agreement. We account for our derivatives and hedging activities under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Under SFAS No. 133, we are required to record our derivative instruments at their fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in current earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges, if any, are recognized in earnings. Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized in earnings. Management has decided not to use hedge accounting for our derivatives. Therefore, in accordance with the provisions of SFAS No. 133, the changes in fair market value are recognized in earnings.
As of December 31, 2007, natural gas derivative instruments consisted of a swap agreement which we entered into during December 2007 for the calendar year 2008. The fair market value of the agreement was a liability of $343,759 as of December 31, 2007. During January and February 2008 we entered into additional swap and costless collar agreements for 2008 and 2009 production. These instruments allow us to predict with greater certainty the effective natural gas prices to be received for our hedged production. Our derivative contracts are described below:
•
For our swap instruments, Gasco receives a fixed price for the hedged commodity and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.
•
Our costless collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Gasco receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.
Our swap agreements for 2008 and 2009 are summarized in the table below:
Our costless collar agreements for 2008 and 2009 are summarized in the table below:
(a)
Contract was initiated in December 2007 and is included in the accompanying financial statements as derivative instruments at fair market value as a liability of $343,759.
(b)
Northwest Pipeline Rocky Mountains - Inside FERC first of month index price.
We have established the fair value of our derivative instruments using estimates of fair value reported by our counterparty and subsequently evaluated internally using established index price and other sources. The actual contribution to our future results of operations will be based on the market prices at the time of settlement and may be more or less than the value estimates used at December 31, 2007.
The Company is exposed to credit risk to the extent of non performance by the counter party in the derivative contracts described above; however, the Company does not anticipate such non performance.
Asset Retirement Obligation
The Company follows SFAS No. 143, “Accounting for Asset Retirement Obligations, “ which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs using the units-of-production method. Gasco’s asset retirement obligation consists of costs related to the plugging of wells, removal of facilities and equipment and site restoration on its oil and gas properties and gathering assets. The asset retirement liability is allocated to operating expense using a systematic and rational method. The information below reconciles the value of the asset retirement obligation for the periods presented.
(a)
Liabilities settled represent the reduction in our asset retirement obligation resulting from the sale of working interests in connection with the drilling program further described in Note 6.
(b)
Revisions represent our periodic reassessment of the expected cash flows and assumptions inherent in the calculation of the asset retirement liability.
Off Balance Sheet Arrangements
From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2007, the off-balance sheet arrangements and transactions that we have entered into include undrawn letters of credit, operating lease agreements and gas transportation commitments. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.
Revenue Recognition
The Company records revenues from the sales of natural gas and crude oil when delivery to the customer has occurred and title has transferred. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred.
The Company may have an interest with other producers in certain properties, in which case the Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company records revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners’ gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over- and under-produced gas balancing positions are considered in the Company’s proved oil and gas reserves. Gas imbalances at December 31, 2007 and 2006 were not significant.
Computation of Net Loss per Share
Basic net loss per share is computed by dividing net loss attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. The shares of restricted common stock granted to certain officers, directors and employees of the Company are included in the computation only after the shares become fully vested. Diluted net income per common share includes the potential dilution that could occur upon exercise of the options to acquire common stock. The Notes, which are convertible into 16,250,000 shares of common stock and the outstanding common stock options, have not been included in the computation of diluted net loss per share during all periods because their inclusion would have been anti-dilutive. As of December 31, 2007, 2006 and 2005 potential common stock equivalents of 26,979,138, 26,128,502 and 25,062,667, respectively, have been excluded from the computation of diluted net income (loss) per share.
Use of Estimates
The preparation of the financial statements for the Company in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
The Company’s financial statements are based on a number of significant estimates, including oil and gas reserve quantities which are the basis for the calculation of depreciation, depletion and impairment of oil and gas properties, timing and costs associated with its retirement obligations, estimates of the fair value of derivative instruments and impairments to unproved property.
Other Comprehensive Income
The Company’s short-term investments as of December 31, 2006, were classified as available-for-sale, and were carried on the balance sheet at market value. Unrealized gains and losses, net of deferred income taxes, are generally reported as other comprehensive income and as an adjustment to stockholders’ equity. If a decline in market value below cost is assessed as being other than temporary, such impairment is included in the determination of net income. The Company’s available-for-sale securities were readily marketable and available for use in its operations should the need arise. Therefore, the Company classified such securities as current assets. As of December 31, 2006 the market value of the Company’s short-term investments approximated its cost basis and therefore, there were no unrealized gains and losses included in other comprehensive income during 2006. These investments were sold during the first quarter of December 31, 2007.
The Company does not have any other items of other comprehensive income for the years ended December 31, 2007, 2006 and 2005. Therefore, total comprehensive income (loss) is the same as net income (loss) for these periods.
Income Taxes
The Company uses the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of temporary differences between the accounting bases and the tax bases of the Company’s assets and liabilities. The deferred tax assets and liabilities are computed using enacted tax rates in effect for the year in which the temporary differences are expected to reverse.
The Company adopted the provisions of FIN 48 on January 1, 2007. FIN 48 provides detailed guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements in accordance with SFAS No. 109. Tax positions must meet a “more-likely-than-not” recognition threshold at the effective date to be recognized upon the adoption of FIN 48 and in subsequent periods. The adoption of FIN 48 had an immaterial impact on the Company’s consolidated financial position and did not result in unrecognized tax benefits being recorded. Subsequent to adoption, there have been no changes to the Company’s assessment of uncertain tax positions. Accordingly, no corresponding interest and penalties have been accrued. The Company’s policy is to recognize penalties and interest, if any, related to uncertain tax positions as general and administrative expense. The Company files income tax returns in the U.S. federal jurisdiction and various states. There are currently no federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue service for tax years before 2003 and for state and local tax authorities for years before 2002. The Company’s tax years of 2004 and forward are subject to examination by the federal and state taxing authorities.
Stock Compensation
Effective January 1, 2006, the Company adopted SFAS No. 123(R), “Accounting for Stock-Based Compensation” using the modified prospective transition method. SFAS No. 123R requires companies to recognize compensation cost for stock-based awards based on estimated fair value of the award, effective January 1, 2006. See Note 3 for further discussion.
Recent Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements”. This Statement defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosure related to the use of fair value measures in financial statements. The Statement is to be effective for the Gasco’s financial statements issued in 2008; however, earlier application is encouraged. We are currently evaluating the timing of adoption and the impact that adoption might have on our financial position or results of operations.
On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” This Statement establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for
Gasco’s financial statements issued in 2008. We are currently evaluating the impact that the adoption of SFAS No. 159 might have on our financial position or results of operations.
In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108 expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. SAB 108 was effective for Gasco on January 1, 2007. The adoption of SAB 108 had no impact on our financial position or results from operations.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces FASB Statement No. 141. SFAS No. 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non controlling interest in the acquiree and the goodwill acquired, and a establishes that acquisition costs will be generally expensed as incurred. This statement also establishes disclosure requirements which will enable users to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective as of the beginning of an entity’s fiscal year that begins after December 15, 2008, which will be Gasco’s year beginning January 1, 2009. We are currently evaluating the potential impact, if any, of the adoption of SFAS No. 141R on our future financial reporting.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statement-amendments of ARB No. 51”. SFAS No. 160 states that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. The SFAS No. 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008, which corresponds to our year beginning January 1, 2009. We are currently evaluating the potential impact, if any, of the adoption of SFAS No. 160 on our future financial reporting.
In April 2007, the FASB issued FSP FIN 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1). FSP FIN 39-1 defines “right of setoff” and specifies what conditions must be met for a derivative contract to qualify for this right of setoff. It also addresses the applicability of a right of setoff to derivative instruments and clarifies the circumstances in which it is appropriate to offset amounts recognized for those instruments in the statement of financial position. In addition, this FSP permits offsetting of fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement and fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) arising from the same master netting arrangement as the derivative instruments. This interpretation is effective for fiscal years beginning after November 15, 2007, with early application permitted. We are currently evaluating the potential impact, if any, of the adoption of FSP FIN 39-1 on our financial statements.
Reclassifications
Certain reclassifications have been made to prior years’ amounts to conform to the classifications used in the current year. Such reclassifications had no effect on the Company’s net loss in any of the periods presented.
NOTE 3 - STOCK-BASED COMPENSATION
On January 1, 2006, Gasco adopted SFAS No. 123(R), “Accounting for Stock-Based Compensation,” using the modified prospective method. Under the modified prospective method, the adoption of SFAS No. 123(R) applies to new awards and to awards modified, repurchased, or cancelled after December 31, 2005, as well as to the unvested portion of awards outstanding as of January 1, 2006. In accordance with the modified prospective method, we did not adjust the financial statements for periods ended prior to January 1, 2006. SFAS No. 123(R) requires companies to recognize share-based payments to employees as compensation expense using a fair value method. Under the fair value recognition provisions of SFAS No. 123(R), stock-based compensation cost is measured at the grant date based on the fair value of the award and is recognized as an expense over the service period on a straight-line basis, which generally represents the vesting period. The expense recognized over the service period is required to include an estimate of the awards that will be forfeited. Gasco is assuming no forfeitures for employee awards going forward based on the Company’s historical forfeiture experience. For non-employee awards, Gasco is assuming a 3% forfeiture rate for the years ending December 31, 2007 and 2006. The fair value of stock options is calculated using the Black-Scholes option-pricing model and the fair value of restricted stock is based on the fair market value of the stock on the date of grant.
The Company accounts for stock compensation arrangements with non-employees in accordance with SFAS No. 123(R) and Emerging Issues Task Force, or EITF, No. 96-18, “Accounting of Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services,” using a fair value approach. Under this approach, the stock compensation related to the unvested stock options issued to non-employees is recalculated at the end of each reporting period based upon the fair market value on that date. Stock-based non-employee compensation expense was $56,370, $6,264 and $399,364 during the years ended December 31, 2007, 2006 and 2005, respectively. Of these amounts, $45,285 and $7,024 of compensation expense relating to drilling consultants was capitalized during the years ended December 31, 2007 and 2006, respectively. There was no expense capitalized during the year ended December 31, 2005.
As of December 31, 2007, options to purchase an aggregate of 10,729,138 shares of the Company’s common stock and 308,820 shares of restricted stock were outstanding. These awards were granted during the years from 2001 through 2007 to the Company’s employees, directors and consultants. The options have exercise prices ranging from $1.00 to $6.69 per share. The options vest at varying schedules within five years of their grant date and expire within ten years from the grant date. Stock-based employee compensation expense was $3,075,037, $4,152,268, and $344,873 before taxes for the years ending December 31, 2007, 2006, and 2005.
During the years ended December 31, 2007, 2006 and 2005, the Company recognized stock-based compensation as follows:
The Company did not recognize a tax benefit from stock-based compensation expense because the Company considers it more likely than not that the related deferred tax assets, which have been reduced by a full valuation allowance, will not be recognized.
The table below summarizes the effect on net loss and net loss per share for the year ended December 31, 2005 as if the Company has applied the fair value recognition of SFAS No. 123(R) to the employee stock-based awards.
The Company uses the Black-Scholes option-pricing model to estimate the fair value of the options at the grant date. The fair value of options granted to the Company’s employees and directors during 2007, 2006, and 2005 was calculated using the following assumptions:
The weighted average grant-date fair value of options granted to employees and directors during 2007, 2006, and 2005 was $1.38, $3.76, and $2.25, respectively.
The expected stock price volatility assumption was determined using the historical volatility of the Company’s common stock over the expected life of the option. The expected life of the option has been calculated based upon the average historical time between when options were issued and when they were exercised.
Stock Options
The following table summarizes the stock option activity in the equity incentive plans during the years ended December 31, 2007, 2006 and 2005:
The following table summarizes information related to the outstanding and vested options as of December 31, 2007:
The aggregate intrinsic value in the table above represents the total pretax intrinsic value, based on the Company’s closing common stock price of $1.99 as of December 31, 2007, which would have been received by the option holders had all option holders exercised their options as of that date.
The total intrinsic value of options exercised during the year ending December 31, 2006 and 2005 was $1,256,450 and $2,023,726, respectively. There were no options exercised during the year ending December 31, 2007.
The fair value of the options vested as of December 31, 2007 and 2006 is $877,945 and $650,951, respectively.
The Company settles employee stock option exercises with newly issued common shares.
As of December 31, 2007, there was $4,208,883 of total unrecognized compensation cost related to non-vested options granted under the Company’s equity incentive plans. That cost is expected to be recognized over a weighted-average period of 4.74 years.
The following table summarizes the stock options outstanding at December 31, 2007.
Restricted Stock
The following table summarizes the restricted stock activity for the years ending December 31, 2007, 2006 and 2005:
The total grant date fair value of the shares vested during the years ending December 31, 2007, 2006, and 2005 was $533,362, $293,608 and $193,881, respectively.
As of December 31, 2007, there was $635,652 of total unrecognized compensation cost related to non-vested restricted stock granted under the Company’s stock plans. That cost is expected to be recognized over a weighted-average period of 4.75 years.
NOTE 4 - OIL AND GAS PROPERTY
The Company’s oil and gas property is summarized in the following table:
The following table presents information regarding the Company’s net costs incurred in the purchase of proved and unproved properties and in exploration and development activities:
Depletion and impairment expense related to proved properties per equivalent Mcf of production for the years ended December 31, 2007, 2006 and 2005 was $25.08, $16.22 and $2.83, respectively.
At December 31, the Company’s unproved properties consist of leasehold acquisition and exploration costs in the following areas:
During the year ended December 31, 2007, approximately $6,230,000 of acreage costs in Wyoming was reclassified into proved properties and was included in the ceiling test and depletion calculations. Management believed that the continued low prices that we received in the Rockies had caused the potential resources related to our Wyoming acreage to become uneconomic. During 2006, approximately $3,786,000 of unproved lease costs related primarily to expiring acreage in Wyoming was reclassified to proved property.
The following table sets forth a summary of oil and gas property costs not being amortized as of December 31, 2007, by the year in which such costs were incurred.
The Company’s drilling activities are located primarily in the Riverbend Area of Utah, and the Company plans to drill approximately 24 gross wells in this area during 2008. The unproved costs associated with the Company’s drilling projects will be transferred to proved properties as the wells are drilled during the next five to ten years.
NOTE 5 - PROPERTY ACQUISITIONS
On December 14, 2007, we closed the previously announced purchase of Brek Energy Corporation (“Brek”). As a result of this acquisition (the “Brek Acquisition”), Gasco acquired approximately 17,000 net acres in the Uinta Basin of Utah, approximately 7,200 net acres in the Green River Basin of Wyoming and additional working interests in ten producing properties in which Gasco was already the operator and holds working interests. The acquisition is expected to simplify Gasco’s acreage portfolio by absorbing a working interest partner that previously owned approximately 14% of Gasco’s undeveloped acreage in Utah and Wyoming. Gasco does not expect to incur any additional overhead expenses as a result of the acquisition.
Under the terms of the Brek Acquisition, a wholly-owned subsidiary of Gasco merged with and into Brek. As part of the transaction, Brek’s President and CEO, who owned approximately 18% of the outstanding common stock of Brek, agreed to deposit 550,000 shares of Gasco common stock acquired in the transaction in escrow to satisfy any claims with respect to breaches of representations and warranties of Brek for a period of one year following the merger.
In connection with the Brek Acquisition, Gasco issued 10,999,868 shares of its common stock to Brek’s shareholders. The shares of common stock issued to Brek shareholders were valued at $2.76 per share, which was the average value of the Company’s common stock for two days before and after the merger agreement was signed. The total purchase price of $30,749,300 was allocated to the assets acquired and the liabilities assumed based on the estimated fair values at December 31, 2007 as set forth below. The allocation of the purchase price is still preliminary at
this time because the final carryover tax basis of the assets and liabilities has not yet been determined. The Company anticipates finalizing the allocation during 2008.
The purchase price of $30,749,300 consists of the following:
The preliminary purchase price allocation is as follows:
The results of Brek’s operations were included in the consolidated operations from the date of acquisition, December 14, 2007. The following table reflects unaudited pro forma results of operations for the year ended December 31, 2007 and 2006 as though the Brek acquisition had occurred on January 1 of each year presented. The pro forma results are not necessarily indicative of the results that would have been obtained had the acquisition occurred as of an earlier date or results which may be reported in the future.
In August 2006, Gasco acquired certain gathering assets and producing properties associated with the Riverbend Project in the Uinta Basin of Utah for a cash purchase price of $4,875,000, plus settlement for production from the effective date. The acquisition included approximately 21 miles of 4” to 8” mainline gathering pipelines and 24 oil and gas wells. In the transaction, Gasco acquired approximately 1.6 billion cubic feet equivalent of proved reserves. The acquisition has no effect on gross acreage leasehold positions and a negligible effect on net acreage leasehold totals. The transaction closed on August 14, 2006, with an effective date of July 1, 2006.
NOTE 6- DRILLING PROGRAM
On August 1, 2007, Gasco entered into a definitive agreement with a subsidiary of NFR Energy, LLC (“NFR”) whereby the subsidiary of NFR will participate in a 30-well drilling program in Gasco’s Riverbend Project through the second quarter of 2008. The terms of the agreement allow for NFR to earn two-thirds of Gasco’s interest in each 40-acre drilling location, 100 feet below total depth drilled, in exchange for paying its share of costs, including a per-well location fee paid to Gasco as the operator of the project. The agreement covers substantially all of Gasco’s 2007 drilling program, retroactive for wells drilled year-to-date, and as such includes 13 gross operated wells spudded (3.5 net to Gasco’s interest and 6.9 net to NFR) in 2007. At signing, Gasco received cash consideration of $19,031,602 for NFR’s share of the wells that had been drilled, were expected to be drilled or spud prior to agreement date; $3,475,153 (recorded as an offset to the full cost pool) of which was recorded as sales proceeds related to two wells that had been drilled previously. The remaining proceeds were recorded as cash advances from joint interest owners and were applied to the drilling and completion costs of the remaining wells as incurred.
The general terms of the agreement are as follows:
•
The agreement consists of Gasco’s leasehold position in portions of Uintah County, Utah and does not include assets in California, Nevada or Wyoming.
•
The drilling program targets Wasatch, Mesaverde, Blackhawk and Upper Mancos formations.
•
Gasco can continue to independently develop its acreage.
Upon completion of the initial 30-well program, NFR will have earned approximately 67% of Gasco’s interest in 1,200 gross acres in the Riverbend Project.
NOTE 7 - CREDIT FACILITY
On March 29, 2006, Gasco and certain of its subsidiaries, as guarantors, entered into a $250 million Credit Agreement (the “Credit Agreement”) with JPMorgan Chase Bank, N.A., as Administrative Agent and the other lenders named therein. Borrowings made under the Credit Agreement are guaranteed by our subsidiaries and secured by a pledge of the capital stock of our subsidiaries and mortgages on substantially all of our oil and gas properties.
The initial aggregate commitment of the lenders under the Credit Agreement is $250,000,000, subject to a borrowing base which was increased from $25,000,000 to $37,000,000 during February 2007. During October 2007, our borrowing base was further increased to $40,000,000. The Credit Agreement also provides for a $10,000,000 sublimit for letters of credit which we may use for general corporate purposes. As of December 31, 2007, there were loans of $9,000,000 outstanding at an average interest rate of 7.25% and a $6,564,000 letter of credit which is considered usage for purposes of calculating availability and commitment fees. Our aggregate borrowings and outstanding letters of credit under the Credit Agreement may not at any time exceed the borrowing base. Interest on borrowings is payable monthly and principal is due at maturity on March 29, 2010.
Interest on borrowings under the Credit Agreement accrues at variable interest rates at either, at our election, a Eurodollar rate or an alternate base rate. The Eurodollar rate is calculated as LIBOR plus an applicable margin that varies from 1.25% (for periods in which we have utilized less than 50% of the borrowing base) to 2.00% (for periods in which we have utilized greater than 90% of the borrowing base). The alternate base rate is calculated as (1) the greater of (a) the prime rate or (b) the federal funds effective rate plus 1/2%, plus (2) an applicable margin that varies from 0% (for periods in which we have utilized less than 50% of the borrowing base) to 0.75% (for periods in which we have utilized greater than 90% of the borrowing base). We elect the basis of the interest rate at the time of each borrowing. In addition, we are obligated to pay a commitment fee under the Credit Agreement quarterly in arrears based on a percentage multiplied by the daily amount that the aggregate commitments exceed borrowings under the agreement. The commitment fee percentage varies from 0.30% to 0.50% based on the percentage of the borrowing base utilized.
The Credit Agreement requires us to comply with financial covenants that require us to maintain (1) a current ratio (defined as current assets plus unused availability under the Credit Facility divided by current liabilities excluding the current portion of the Credit Facility), determined at the end of each quarter, of not less than 1.0:1; and (2) a ratio of Senior Debt to EBITDAX (as such terms are defined in the Credit Agreement) for the most recent quarter multiplied by four not to be greater than 3.5:1 for each fiscal quarter. In addition, the Credit Agreement contains covenants that restrict our ability to incur other indebtedness, create liens or sell our assets, pay dividends on our common stock and make certain investments. As of December 31, 2007, we were in compliance with each of the covenants contained in the Credit Agreement.
The Company incurred $240,262 in debt issuance costs associated with this facility. These costs have been recorded as deferred financing costs in the accompanying financial statements and are being amortized over the four year term of the credit facility. The Credit Agreement is available to provide funds for the exploration, development and/or acquisition of oil and gas properties, to refinance existing indebtedness and for working capital and other general corporate purposes. The Credit Agreement provides for semi-annual evaluation of the borrowing base, which will be determined as a percentage of the discounted present value of the Company’s oil and natural gas reserves.
NOTE 8 - CONVERTIBLE SENIOR NOTES
On October 20, 2004 (the “Issue Date”), the Company closed the private placement of $65,000,000 in aggregate principal amount of its 5.50% Convertible Senior Notes due 2011 (the “Convertible Notes”) pursuant to an Indenture dated as of October 20, 2004 (the “Indenture”), between the Company and Wells Fargo Bank, National Association, as trustee. The amount sold consisted of $45,000,000 principal amount originally offered plus the exercise by the initial purchasers of their option to purchase an additional $20,000,000 principal amount. The Convertible Notes were sold only to qualified institutional buyers in reliance on Rule 144A under the Securities Act of 1933.
The Convertible Notes are convertible into Company common stock, $.0001 par value per share, at any time prior to maturity at a conversion rate of 250 shares of common stock per $1,000
principal amount of Convertible Notes (equivalent to a conversion price of $4.00 per share), which is subject to certain anti-dilution adjustments.
Interest on the Convertible Notes accrues from the most recent interest payment date, and is payable in cash semi-annually in arrears on April 5th and October 5th of each year, and commenced on April 5, 2005. Interest is payable to holders of record on March 15th and September 15th immediately preceding the related interest payment dates, and will be computed on the basis of a 360-day year consisting of twelve 30-day months.
The Company, at its option, may at any time on or after October 10, 2009, in whole, and from time to time in part, redeem the Convertible Notes on not less than 20 nor more than 60 days’ prior notice mailed to the holders of the Convertible Notes, at a redemption price equal to 100% of the principal amount of Convertible Notes to be redeemed plus any accrued and unpaid interest to but not including the redemption date, if the closing price of the common stock has exceeded 130% of the conversion price for at least 20 trading days in any consecutive 30 trading-day period.
Upon a “change of control” (as defined in the Indenture), each holder of Convertible Notes can require the Company to repurchase all of that holder’s notes 45 days after the Company gives notice of the change of control, at a repurchase price equal to 100% of the principal amount of Convertible Notes to be repurchased plus accrued and unpaid interest to, but not including, the repurchase date, plus a make-whole premium under certain circumstances described in the Indenture.
The Convertible Notes are unsecured (except as described above) and unsubordinated obligations of the Company and rank on a parity (except as described above) in right of payment with all of the Company’s existing and future unsecured and unsubordinated indebtedness. The Convertible Notes effectively rank junior to any future secured indebtedness and junior to the Company’s subsidiaries’ liabilities. The Indenture does not contain any financial covenants or any restrictions on the payment of dividends, the repurchase of the Company’s securities or the incurrence of indebtedness.
Upon a continuing event of default, the trustee or the holders of 25% principal amount of a series of Convertible Notes may declare the Convertible Notes immediately due and payable, except that a default resulting from the Company’s entry into a bankruptcy, insolvency or reorganization will automatically cause all Convertible Notes under the Indenture to become due and payable.
The fair value of the Convertible Notes is $60,450,000 as of December 31, 2007.
NOTE 9 - STOCKHOLDERS’ EQUITY
The Company’s capital stock as of December 31, 2007 and 2006 consists of 300,000,000 authorized shares of common stock, par value $0.0001 per share, and 20,000 authorized shares of Series B Convertible Preferred stock, par value $0.001 per share.
Series B Convertible Preferred Stock - As of December 31, 2007 and 2006, Gasco had no shares of Series B Preferred Stock (“Preferred Stock”) issued and outstanding. All of the Preferred stock outstanding as of December 31, 2005 was converted by the holders thereof into 479,599 shares of common stock during January 2006. The Preferred Stock was entitled to receive dividends at the rate of 7% per annum payable semi-annually in cash, additional shares of Preferred Stock or shares of common stock at the Company’s option. The conversion price of the Preferred Stock was $0.70 per common share, and the shares of the Preferred Stock were convertible into Gasco common shares at any time at the holder’s election. The Preferred Stock voted as a class on issues that affected the Preferred Stockholders’ interests and voted with shares of common stock on all other issues on an as-converted basis. Additionally, the holders of the Preferred Stock exercised their right to elect one member to Gasco’s board of directors during March 2003.
During the year ended December 31, 2006, the Company paid $1,393 of cash dividends to the holders of its Preferred Stock.
Common Stock - Gasco has 107,290,471 shares of common stock issued, 107,216,771 shares outstanding and 73,700 shares held in treasury as of December 31, 2007. The common shareholders are entitled to one vote per share on all matters to be voted on by the shareholders; however, there are no cumulative voting rights. Additionally, while the Preferred Stock was outstanding, the holders of the Preferred Stock were entitled to vote with shares of common stock on an as-converted basis. The common shareholders are entitled to dividends and other distributions as may be declared by the board of directors. Upon liquidation or dissolution, the common shareholders will be entitled to share ratably in the distribution of all assets remaining available for distribution after satisfaction of all liabilities and payment of the liquidation preference of any outstanding preferred stock.
As of December 31, 2007, we had 107,216,771 shares of common stock outstanding. As of such date, there were 10,729,138 shares of common stock issuable upon exercise of outstanding options. Additional options may be granted to purchase 2,843,539 shares of common stock under our stock option plan and an additional 168,850 shares of common stock are issuable under our restricted stock plan. As of December 31, 2007, and as of December 31 of each succeeding year, the number of shares of common stock issuable under our stock option plan automatically increases so that the total number of shares of common stock issuable under such plan is equal to 10% of the total number of shares of common stock outstanding on such date.
Assuming all of the Convertible Notes are converted at the applicable conversion prices, the number of shares of our common stock outstanding would increase by approximately 16,250,000 shares to approximately 123,466,771 shares (this number assumes no exercise of the options described above and no additional grants of options or restricted stock).
The Company’s common stock equity transactions during 2007 and 2006 are described as follows:
In December, 2007 we closed the previously announced purchase of Brek for equity consideration of 10,999,868 shares of common stock of the Company valued at approximately
$30,749,300 using $2.76 per share which was the average value of the Company’s common stock for two days before and after the agreement was signed. See further discussion in Note 5.
On April 13, 2007, Gasco issued 10,000,000 shares of common stock in a public offering for gross proceeds of $19,300,000. The offering costs associated with this transaction were $120,729. Gasco is using the net proceeds from the offering for general corporate purposes.
During the years ended December 31, 2007 and 2006, the Company’s Board of Directors approved the issuance of 234,500 and 131,250 shares of common stock, respectively, under the Gasco Energy, Inc. Amended and Restated 2003 Restricted Stock Plan, (“Restricted Stock Plan”) to certain of the Company’s employees and consultants. The restricted shares vest at varying schedules within three to five years. The shares fully vest upon certain events, such as a change in control of the Company, expiration of the individual’s employment agreement and termination by the Company of the individual’s employment without cause. Any unvested shares are forfeited upon termination of employment for any other reason. The compensation expense related to the restricted stock was measured on the issuance date using the trading price of the Company’s common stock on that date and is amortized over the vesting period. The shares of restricted stock are considered issued and outstanding at the date of grant and are included in shares outstanding upon vesting for the purposes of computing diluted earnings per share. During 2007 and 2006, 88,462 and 82787 shares of the Company’s common stock were cancelled in satisfaction of the income tax liability of $220,522 and $199,286, respectively, associated with the vesting of restricted stock.
During the years ended December 31, 2007 and 2006, the Company granted 1,540,000 and 1,925,000 options, respectively, to purchase shares of common stock to its employees, at exercise prices ranging from $1.80 per share to $5.69 per share. The options vest at varying schedules within three to five years after the issuance date.
During 2006, the Company issued 604,161 shares of common stock in connection with the exercise of options to purchase shares of common stock at strike prices ranging from $1.61 per common share to $3.70 per common share for total proceeds of $1,591,674.
NOTE 10 - STATEMENT OF CASH FLOWS
During the year ended December 31, 2007, the Company’s non-cash investing and financing activities consisted of the following transactions:
During the year ended December 31, 2006, the Company’s non-cash investing and financing activities consisted of the following transactions:
During the year ended December 31, 2005, the Company’s non-cash investing and financing activities consisted of the following transactions:
Cash paid for interest was $4,304,308, $3,687,124 and $3,575,000 for the years ended December 31, 2007, 2006 and 2005, respectively. There was no cash paid for income taxes in any of the years ended December 31, 2007, 2006 and 2005.
NOTE 11 - INCOME TAXES
The provision (benefit) for income taxes for the years ended December 31, 2007, 2006 and 2005 consists of the following:
A reconciliation of the provision (benefit) for income taxes computed at the statutory rate to the provision for income taxes as shown in the financial statements of operations for the years ended December 31, 2007, 2006 and 2005 is summarized below:
The components of the deferred tax assets and liabilities as of December 31, 2007 and 2006 are as follows:
The Company has approximately $114,405,000 of net operating loss carryover for federal income tax purposes as of December 31, 2007, of which $4,550,000 is not benefited for financial statement purposes as it relates to tax deductions that deviate from compensation expense for financial statement purposes. The benefit of these excess tax deductions will not be recognized for financial statement purposes until the related deductions reduce taxes payable. As part of the Brek Acquisition, the Company acquired $24,055,000 in net operating losses. The losses may be subject to certain usage limitations under Section 382. In addition, due to the uncertainty regarding the realizability of the acquired deferred tax assets, a valuation allowance has been recorded to the extent of the net deferred tax assets. The Company has approximately $96,154,000 of net operating loss carryover for state income tax purposes as of December 31, 2007, of which the above excess tax deductions have similarly not been benefited for financial statement purposes. The net operating losses may offset against taxable income through the year ended December 31, 2027. A portion of the net operating loss carryovers begins expiring in 2019. As part of the Brek Acquisition, the Company acquired $9,107,000 in net operating losses. Similar to the acquired federal deferred tax assets, due to the uncertainty regarding the realizability, a valuation allowance has been recorded to the extent of the acquired net deferred tax assets. The Company provided a valuation allowance against its net deferred tax asset of $86,176,357 and $28,827,261 as of December 31, 2007 and 2006 respectively, since it believes that it is more likely than not that the net deferred tax assets will not be fully utilized on future income tax returns. The increase in the valuation allowance for 2007 and 2006 is $57,385,972 and $20,681,594, respectively, with the 2007 increase due in part to the acquired deferred tax assets and associated valuation allowance related to the Brek Acquisition.
NOTE 12 - RELATED PARTY TRANSACTIONS
During the each of years ended December 31, 2006 and 2005, the Company paid $120,000 in consulting fees to a company owned by a director of Gasco. This consulting agreement was terminated effective January 1, 2007.
Certain of the Company’s directors and officers have working and/or overriding royalty interests in oil and gas properties in which the Company has an interest. It is expected that the directors and officers may participate with the Company in future projects. All participation by directors and officers will continue to be approved by the disinterested members of the Company’s Board of Directors.
NOTE 13 - COMMITMENTS
The Company leases approximately 9,880 square feet of office space in Englewood, Colorado, under a lease, which terminates on May 31, 2010. The average rent for this space over the life of the lease is approximately $140,800 per year.
The following table shows the annual rentals per year for the life of the lease.
Rent expense for the years ended December 31, 2007, 2006 and 2005 was $137,512, $126,352, and $121,648, respectively.
As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not pay such commitments, the acreage positions or wells may be lost.
The Company entered into employment agreements with three key officers through January 31, 2009. Total minimum compensation under these agreements is $470,000 per annum. The agreements contain clauses regarding termination and demotion of the officer that would require payment of an amount ranging from one times annual compensation to up to approximately five times annual compensation plus a cash payment from $250,000 to $500,000. Included in the employment agreements is a bonus calculation for each of the covered officers totaling 2.125% of a defined cash flow figure based on net after tax earnings adjusted for certain expenses.
Gasco is currently running two rigs in its Riverbend project. During March 2007, the Company entered into a three year contract for a new-build rig with a drilling rate of approximately $21,000 per day. The other rig is leased on a month to month basis at approximately $19,500 per day. The three year drilling contract for the new-build rig contains a provision for the Company to terminate the contract for $12,000 per day for the number days remaining in the original contract. In connection with this contract Gasco provided the rig owner a letter of credit for $6,564,000.
The future contractual obligations under the rig contracts are summarized below:
During April 2007, we entered into a sales and transportation agreement for 18,000 MMBTU per day, at the first of the month IFERC CIG index price, net of transportation, marketing and fuel expenses for our 2007 production. For our 2008 and 2009 production, we entered into a firm commitment to sell 30,000 MMBtu per day of our gross production from the Uinta Basin. During the first quarter of 2008, 18,000 MMBTU per day of such amount is contracted at the CIG first of month price and the remaining 12,000 MMBtu per day will be priced at the NW Rockies first of month price. Beginning in the second quarter of 2008, the entire contracted amount will be based on NW Rockies first of month price. We have elected the normal purchase and sale exemption under paragraph 10(b) of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” because we anticipate that (1) we will produce the volumes required to be delivered under the terms of the contract, (2) it is probable the delivery will be made to the counterparty and (3) the counterparty will fulfill its contractual obligations under the terms of the contracts. As such, we believe we are not required to treat the contract as a derivative and the contract will not be marked to market under the provisions of SFAS No. 133.
As discussed in Note 2, we have entered into derivative contracts for our 2007, 2008 and 2009 natural gas sales.
In early 2007, a consultant to Riverbend Gas Gathering, LLC (“Riverbend”), a wholly owned subsidiary of the Company, that was preparing air emission calculations for possible future capacity expansions, preliminarily determined that Riverbend may have not accurately calculated the amount of air pollutants that could be emitted from certain existing equipment at its Riverbend Compressor Station in Uintah County, Utah. Riverbend thereafter undertook a more detailed assessment, which confirmed that it had not obtained certain air permits nor complied with certain air pollution regulatory programs that were applicable to its operations at the Riverbend Compressor Station. On June 22, 2007, Riverbend sent a letter to the United States Environmental Protection Agency (the “EPA”) Region 8 office in Denver, Colorado, which-because the Riverbend Compressor Station is located in Indian Country-is the agency that has jurisdiction over federal air permitting and air pollution regulatory programs. The letter voluntarily disclosed the potential violations to the EPA and informed the agency of the steps that Riverbend had taken and planned to take to achieve compliance. In November 2007, Riverbend met with EPA Region 8 personnel and discussed the disclosed violations, its plans to bring the Riverbend Compressor Station into compliance, and possible resolution of the disclosed violations. In a letter to the EPA dated January 23, 2008, Riverbend confirmed its willingness to sign a consent decree with the United States that resolves the apparent violations,
specifies the appropriate corrective action, provides a schedule for Riverbend to achieve such corrective action, and includes a covenant not to sue that will effectively authorize Riverbend to continue its operations, including certain capacity expansions, while the specified corrective action is being implemented. Riverbend anticipates that such a resolution will be achieved during 2008. Riverbend believes that all necessary pollution control and other equipment likely to be required by such a resolution is already installed at the site or accounted for in the Company’s capital budget, and that any civil penalties that may be assessed will not materially affect the Company’s financial position.
Riverbend’s emission review also included the Gate Canyon Compressor Station, which is a small compressor station operated by Riverbend that is located on land over which the State of Utah has regulatory jurisdiction. As a result of this review, Riverbend determined that its application for minor new source review authorization from the Utah Department of Environmental Quality (“UDEQ”) for the Gate Canyon Compressor Station did not include a dehydrator that had been installed at the site. Riverbend has submitted an application to UDEQ to revise the existing minor new source review authorization to include this equipment. If any penalties are sought by the State of Utah for not having included the equipment in the original application for a minor new source review authorization, the Company anticipates that they would not materially affect the Company’s financial position.
NOTE 14 - EMPLOYEE BENEFIT PLANS
The Company adopted a 401(k) profit sharing plan (the “Plan”) in October 2001, available to employees who meet the Plan’s eligibility requirements. The Plan is a defined contribution plan. The Company may make discretionary contributions to the Plan and is required to contribute 3% of each participating employee’s compensation to the Plan. The contributions made by the Company totaled $143,293, $76,685 and $58,110 during the years ended December 31, 2007, 2006 and 2005, respectively.
NOTE 15 - SELECTED QUARTERLY INFORMATION (Unaudited)
The following represents selected quarterly financial information for the years ended December 31, 2007 and 2006.
The increase in the Company’s net loss during the second third quarters as compared with the other quarters is primarily due to the $64,300,000 impairment recorded at June 30, 2006 and the $32,790,000 impairment recorded at September 30, 2007 as further discussed in Note 2.
The increase in the Company’s net loss during the second quarter as compared with the other quarters is primarily due to the $51,000,000 impairment recorded at June 30, 2006 as further discussed in Note 2.
NOTE 16 - CONSOLIDATING FINANCIAL STATEMENTS
On September 23, 2005, Gasco filed a Form S-3 shelf registration statement with the Securities Exchange Commission which was subsequently amended in a Form S-3/A that was filed on October 27, 2005. Under this registration statement, which was declared effective on November 1, 2005, we may from time to time offer and sell common stock, preferred stock, depositary shares and debt securities that may be fully, irrevocably and unconditionally guaranteed by all of our subsidiaries: Gasco Production Company, San Joaquin Oil & Gas, Ltd., Riverbend Gas Gathering, LLC and Myton Oilfield Rentals, LLC (“Guarantor Subsidiaries”).
Set forth below are the condensed consolidating financial statements of Gasco, the parent, and the Guarantor Subsidiaries.
Condensed Consolidating Balance Sheet
As of December 31, 2007
(Unaudited)
Condensed Consolidating Balance Sheet
As of December 31, 2006
(Unaudited)
Consolidating Statements of Operations
Consolidating Statements of Operations
Consolidating Statements of Cash Flows
Consolidating Statements of Cash Flows
NOTE 17 - SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)
The following reserve quantity and future net cash flow information for the Company represents estimated proved reserves located in the United States. The reserves as of December 31, 2007, 2006 and 2005 have been estimated by Netherland, Sewell and Associates, Inc., independent petroleum engineers. The determination of oil and gas reserves is based on estimates, which are highly complex and interpretive. The estimates are subject to continuing change as additional information becomes available.
The standardized measure of discounted future net cash flows is prepared under the guidelines set forth by the Securities and Exchange Commission (SEC) that require the calculation to be performed using year-end oil and gas prices. The oil and gas prices used as of December 31, 2007, 2006 and 2005 were $73.95 per bbl of oil and $6.53 per Mcf, $45.53 per bbl of oil and $4.47 per Mcf, $59.87 per bbl of oil and $8.01 per Mcf of gas, respectively. Future production costs are based on year-end costs and include severance taxes. Each property that is operated by the Company is also charged with field-level overhead in the reserve calculation. The present value of future cash inflows is based on a 10% discount rate.
Reserve Quantities
(a)
The majority of the revisions of previous estimates during 2005 are comprised of the following:
•
Four proved undeveloped locations were omitted from the 2005 reserve report because these locations required a higher capital investment than originally estimated due to drilling and completion problems and due to the lack of historical data related to completions and recompletions in this area.
•
Six proved undeveloped locations were omitted from the 2005 reserve report because drilling activity indicated that these locations may be outside of or on the edge of a previously identified zone.
•
Two proved developed non-producing completions significantly underperformed previous forecasts.
(b)
The majority of the revisions of previous estimates during 2006 were a result of the following:
•
Fifty gross locations previously classified as proved undeveloped were omitted from the 2006 reserve report because these locations did not yield a positive net present value at a discount rate of 10% at the then current estimated capital investment based on historical data to drill and complete wells in this area.
•
Four gross locations previously classified as proved undeveloped were developed in 2006 and two gross proved undeveloped locations were added.
Standardized Measure of Discounted Future Net Cash Flows
Changes in the Standardized Measure of Discounted Future Net Cash Flows
ITEM 9
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A
ITEM 9A - CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Our management has evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2007. Our disclosure controls and procedures are designed to provide us with a reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to our management as appropriate to allow such persons to make timely decisions regarding required disclosures.
Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our disclosure controls and procedures are designed to provide such reasonable assurances of achieving our desired control objectives, and our CEO and CFO have concluded, as of December 31, 2007, that our disclosure controls and procedures are effective in achieving that level of reasonable assurance.
Internal control over financial reporting
Our internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements in accordance with GAAP. These internal controls over financial reporting were designed under the supervision of our management and include policies and procedures that: (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
Changes in internal control over financial reporting during the fourth quarter of 2007. There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) or in other factors that occurred during the fiscal quarter ended December 31, 2007, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
In accordance with Item 308 of SEC Regulation S-K, management is required to provide an annual report regarding internal controls over our financial reporting. This report, which includes management’s assessment of the effectiveness of our internal controls over financial reporting, is found below.
Management’s Report on Internal Control Over Financial Reporting
Management of the 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 Exchange Act. The Company’s internal control over financial reporting is designed, under the supervision of the Company’s chief executive and chief financial officers, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (GAAP). The Company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set for by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.
Based on our assessment and those criteria, management has concluded that the Company maintained effective internal control over financial reporting as of December 31, 2007.
Pursuant to the requirements of Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended, this Annual Report on Internal Control Over Financial Reporting has been signed below by the following persons on behalf of the registrant and in the capacities indicated below on March 3, 2008.
/s/ Mark A. Erickson
Mark A. Erickson
President & Chief Executive Officer
/s/ W. King Grant
W. King Grant
Chief Financial Officer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors
Gasco Energy, Inc.
Englewood, Colorado
We have audited Gasco Energy, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Gasco Energy, Inc.’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. 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, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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, Gasco Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of Gasco Energy, Inc. and our report dated February 29, 2008 expressed an unqualified opinion.
/s/ Hein & Associates LLP
HEIN & ASSOCIATES LLP
Denver, Colorado
February 29, 2008
ITEM 9B
ITEM 9B - OTHER INFORMATION
None.
PART III
ITEM 10
ITEM 10 - DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2008 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.
ITEM 11
ITEM 11 - EXECUTIVE COMPENSATION
The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2008 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.
ITEM 12
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2008 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.
ITEM 13
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2008 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.
ITEM 14
ITEM 14 - PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2008 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.
ITEM 15
ITEM 15 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
1. See “Index to Financial Statements” under Item 8 on page 56.
2. Financial Statement Schedules - none.
3. Exhibits - See Index to Exhibits, below.
INDEX TO EXHIBITS
2.1
Agreement and Plan of Reorganization dated January 31, 2001 among San Joaquin Resources Inc., Nampa Oil & Gas, Ltd., and Pannonian Energy, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated January 31, 2001, filed on February 2, 2001, File No. 000-26321).
2.2
Agreement and Plan of Reorganization dated December 15, 1999 by and between LEK International, Inc. and San Joaquin Oil & Gas Ltd. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).
2.3
Property Purchase Agreement dated as of April 23, 2002, between the Company and Shama Zoe Limited Partnership (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated May 1, 2002, filed on May 9, 2002, File No. 000-26321).
2.4
Purchase Agreement dated as of July 16, 2002, among Gasco, Pannonian Energy Inc., San Joaquin Oil & Gas Ltd., Brek, Brek Petroleum Inc., Brek Petroleum (California), Inc. and certain stockholders of Gasco. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated July 16, 2002, filed on July 31, 2002, File No. 000-26321).
2.5
Purchase and Sale Agreement between ConocoPhillips and the Company relating to the Riverbend Field, Uintah and Duchesne Counties, Utah, Effective January 1, 2004 (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated March 9, 2004, filed on March 15, 2004, File No. 000-26321).
2.6
Net Profits Purchase Agreement between Gasco Production Company, Red Oak Capital Management, LLC, MBG, LLC and MBGV Partition, LLC, dated August 6, 2004 (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed September 7, 2004, File No. 000-26321).
2.7
Purchase Supplement to Net Profits Purchase Agreement between Gasco Production Company, Red Oak Capital Management, LLC, MBG, LLC and MBGV Partition, LLC, dated August 20, 2004 (incorporated by reference to Exhibit 2.2 of the Company’s Current Report on Form 8-K filed September 7, 2004, File No. 000-26321).
2.8
Agreement and Plan of Merger dated January 31, 2007, by and among Gasco Energy, Inc., Gasco Acquisition, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated September 20, 2006, filed September 21, 2006, File No. 001-32369).
2.9
First Amendment to Agreement and Plan of Merger dated January 31, 2007, by and between Gasco Energy, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated January 31, 2007, filed February 2, 2007, File No. 001-32369).
2.10
Second Amendment to Agreement and Plan of Merger dated January 31, 2007, by and among Gasco Energy, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated May 29, 2007, filed May 30, 2007, File No. 001-32369).
2.11
Third Amendment to Agreement and Plan of Merger dated October 22, 2007, by and between Gasco Energy, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated October 22, 2007, filed October 23, 2007, File No. 001-32369).
3.1
Amended and Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).
3.2
Certificate of Amendment to Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).
3.3
Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).
3.4
Amended and Restated Bylaws of Gasco Energy, Inc., dated June 26, 2007 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated June 26, 2007, filed on June 27, 2007, File No. 001-32369).
3.5
Certificate of Designation for Series B Convertible Preferred Stock (incorporated by reference to Exhibit 3.5 to the Company’s Form S-1 Registration Statement dated April 16, 2003, filed April 17, 2003, File No. 333-104592).
4.1
Form of Subscription and Registration Rights Agreement, dated as of August 14, 2002 between the Company and certain investors Purchasing Common Stock in August, 2002. (Filed as Exhibit 10.21 to the Company’s Form S-1 Registration Statement dated August 26, 2002, filed on August 27, 2002, File No. 333-98759).
4.2
Form of Gasco Energy, Inc. 8.00% Convertible Debenture, dated October 15, 2003 between each of The Frost National Bank, Custodian FBO Renaissance US Growth & Investment Trust PLC Trust No. W00740100, HSBC Global Custody Nominee (U.K.) Limited Designation No. 896414 and The Frost National Bank, Custodian FBO Renaissance Capital Growth & Income Fund III, Inc. Trust No. W00740000 (incorporated by reference to Exhibit 4.6 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).
4.3
Deed of Trust and Security Agreement, dated October 15, 2003 between Pannonian and BFSUS Special Opportunities Trust PLC, Renaissance Capital Growth & Income Fund III, Inc. and Renaissance US Growth & Income Trust PLC (incorporated by reference to Exhibit 4.7 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).
4.4
Subsidiary Guaranty Agreement, dated October 15, 2003 between Pannonian and Renn Capital Group, Inc (incorporated by reference to Exhibit 4.8 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).
4.5
Subsidiary Guaranty Agreement, dated October 15, 2003 between San Joaquin Oil and Gas, Ltd. And Renn Capital Group, Inc (incorporated by reference to Exhibit 4.9 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).
4.6
Form of Subscription and Registration Rights Agreement between the Company and investors purchasing Common Stock in October 2003 (incorporated by reference to Exhibit 4.10 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).
4.7
Form of Subscription and Registration Rights Agreement between the Company and investors purchasing Common Stock in February, 2004 (incorporated by reference to Exhibit 4.7 to the Company’s Form 10-K for the year ended December 31, 2003, filed on March 26, 2004, File No. 000-26321).
4.8
Indenture dated as of October 20, 2004, between Gasco Energy, Inc. and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 20, 2004, File No. 000-26321).
4.9
Form of Global Note representing $65 million principal amount of 5.5% Convertible Senior Notes due 2011 (incorporated by reference to Exhibit A to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 20, 2004, File No. 000-26321).
4.10
Registration Rights Agreement dated October 20, 2004, among Gasco Energy, Inc., J.P. Morgan Securities Inc. and First Albany Capital Inc (incorporate by reference to Exhibit 4.10 to the Company’s Form 10-Q for the quarter ended September 30, 2004 filed on November 12, 2004, File No. 000-26321).
4.11
Pledge and Security Agreement dated March 29, 2006 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC and JPMorgan Chase Bank, N.A. (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K dated March 29, 2006, filed March 30, 2006, File No. 001-32369).
4.12
Credit Agreement dated March 29, 2006 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC, JPMorgan Chase Bank, N.A. and J.P. Morgan Securities Inc. (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K dated March 29, 2006, filed March 30, 2006, File No. 001-32369).
4.13
Voting Agreement dated September 20, 2006 by and among Gasco Energy, Inc., Richard N. Jeffs, Gregory Pek, Ian Robinson, Michael L. Nazmack, Eugene Sweeney and Shawne Malone (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K dated September 20, 2006, filed September 21, 2006, File No. 001-32369).
4.14
Underwriting Agreement dated April 9, 2007, between Gasco Energy, Inc. and JP Morgan Securities Inc. (incorporated by reference to Exhibit 1.1 to the Company’s Form 8-K dated April 9, 2007, filed April 13, 2007, File No. 001-32369).
# 10.1
1999 Stock Option Plan (incorporated by reference to Exhibit 4.1 to the Company’s Form 10-KSB for the fiscal year ended December 31, 1999, filed on April 14, 2000, File No. 000-26321).
# 10.2
Form of Stock Option Agreement under the 1999 Stock Option Plan (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
# 10.3
Stock Option Agreement dated January 2, 2001 between Gasco and Mark A. Erickson (Filed as Exhibit 10.9 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
# 10.4
Form of Stock Option Agreement between Gasco and each of the individuals named therein (incorporated by reference to Exhibit 4.6 to the Company’s Form S-8 Registration Statement (Reg. No. 333-122716), filed on February 10, 2005).
# 10.5
Michael Decker Amended and Restated Employment Contract dated February 14, 2003 (Filed as Exhibit 10.11 to the Company’s Form 10-K for the fiscal year ended December 31, 2002, filed on March 29, 2003, File No. 000-26321).
# 10.6
Mark A. Erickson Amended and Restated Employment Contract dated February 14, 2003 (Filed as Exhibit 10.12 to the Company’s Form 10-K for the fiscal year ended December 31, 2002, filed on March 29, 2003, File No. 000-26321).
# 10.7
Amended and Restated Consulting Agreement dated February 14, 2003, between Gasco and Marc Bruner (Filed as Exhibit 10.13 to the Company’s Form 10-K for the fiscal year ended December 31, 2002, filed on March 29, 2003, File No. 000-26321).
#10.8
2003 Restricted Stock Plan (Filed as Appendix B to the Company’s Proxy Statement dated August 25, 2003 for its 2003 Annual Meeting of Stockholders, filed on August 25, 2003, File No. 000-26321).
10.9
Muddy Creek Exploration Agreement dated August 15, 2001, between Gasco, Shama Zoe Limited Partnership and Burlington Oil and Gas Company (Filed as Exhibit 10.15 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
10.10
CD Exploration Agreement dated August 15, 2001, between Gasco, Shama Zoe Limited Partnership and Burlington Oil and Gas Company (Filed as Exhibit 10.16 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
10.11
Gamma Ray Exploration Agreement dated August 15, 2001, between Gasco, Shama Zoe Limited Partnership and Burlington Oil and Gas Company (Filed as Exhibit 10.17 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
10.12
Sublette County, WY AMI Agreement dated August 22, 2001 between Gasco, Alpine Gas Company and Burlington Oil and Gas Company (Filed as Exhibit 10.18 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
10.13
Lead Contractor Agreement dated January 24, 2002, between Gasco and Halliburton Energy Services, Inc. (Filed as Exhibit 10.19 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
10.14
Property Purchase Agreement, dated as of April 23, 2002, between the Company and Shama Zoe Limited Partnership (Filed as Exhibit 2.1 to the Company’s Form 8-K dated May 1, 2002, filed on May 9, 2002, File No. 000-26321).
10.15
Purchase Agreement, dated as of July 16, 2002, among the Company, Pannonian Energy Inc., San Joaquin Oil & Gas Ltd., Brek Energy Corporation, Brek Petroleum Inc., Brek Petroleum (California), Inc. and certain stockholders (Filed as Exhibit 2.1 to the Company’s Form 8-K dated July 16, 2002, filed on July 31, 2002, File No. 000-26321).
10.16
Amendment No. 1 to Property Purchase Agreement dated as of August 9, 2002 between the Company and Shama Zoe Limited Partnership. (Filed as Exhibit 10.22 to the Company’s Form S-1 dated August 15, 2002, filed on August 17, 2002, File No. 333-98759).
10.17
Financial Advisory Services Agreement dated August 22, 2002, between the Company and Energy Capital Solutions LLC. (Filed as Exhibit 10.23 to the Company’s Form S-1 dated August 16, 2002, filed on August 17, 2002 File No. 333-98759).
10.18
Termination and Settlement Agreement, dated as of December 23, 2004, among Gasco Energy, Inc., Marc A. Bruner and Mark A. Erickson (Filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 31, 2005, File No. 001-32369).
10.19
Joint Value Enhancement Agreement by and among Pannonian Energy Inc., M-I, LLC, Nabors Drilling USA, LP, Pool Well Services Co., Red Oak Capital Management LLC and Schlumberger Technology Corporation dated January 16, 2004 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 21, 2004, File No. 000-26321).
#10.20
Employment Agreement dated February 14, 2005 by and between Gasco Energy, Inc. and W. King Grant (incorporated by reference to Exhibit 4.2 to the Company’s Form 10-Q for the quarter ended March 31, 2006, filed May 5, 2006, File No. 001-32369).
10.21
Participation Agreement dated August 1, 2007 by and between Gasco Production Company and NFR Uinta Basin LLC (incorporated by reference to Exhibit 10.11 to the Company’s Form 10-Q for the quarter ended June 30, 2007, filed August 1, 2007, File No. 001-32369).
*23.1
Consent of Netherland, Sewell & Associates, Inc.
*23.2
Consent of Hein & Associates LLP
*31
Rule 13a-14(a)/15d-14(a) Certifications
*32
Section 1350 Certifications
*
Filed herewith.
#
Identifies management contracts and compensatory plans or arrangements.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
INDEX TO EXHIBITS
2.1
Agreement and Plan of Reorganization dated January 31, 2001 among San Joaquin Resources Inc., Nampa Oil & Gas, Ltd., and Pannonian Energy, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated January 31, 2001, filed on February 2, 2001, File No. 000-26321).
2.2
Agreement and Plan of Reorganization dated December 15, 1999 by and between LEK International, Inc. and San Joaquin Oil & Gas Ltd. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).
2.3
Property Purchase Agreement dated as of April 23, 2002, between the Company and Shama Zoe Limited Partnership (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated May 1, 2002, filed on May 9, 2002, File No. 000-26321).
2.4
Purchase Agreement dated as of July 16, 2002, among Gasco, Pannonian Energy Inc., San Joaquin Oil & Gas Ltd., Brek, Brek Petroleum Inc., Brek Petroleum (California), Inc. and certain stockholders of Gasco. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated July 16, 2002, filed on July 31, 2002, File No. 000-26321).
2.5
Purchase and Sale Agreement between ConocoPhillips and the Company relating to the Riverbend Field, Uintah and Duchesne Counties, Utah, Effective January 1, 2004 (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated March 9, 2004, filed on March 15, 2004, File No. 000-26321).
2.6
Net Profits Purchase Agreement between Gasco Production Company, Red Oak Capital Management, LLC, MBG, LLC and MBGV Partition, LLC, dated August 6, 2004 (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed September 7, 2004, File No. 000-26321).
2.7
Purchase Supplement to Net Profits Purchase Agreement between Gasco Production Company, Red Oak Capital Management, LLC, MBG, LLC and MBGV Partition, LLC, dated August 20, 2004 (incorporated by reference to Exhibit 2.2 of the Company’s Current Report on Form 8-K filed September 7, 2004, File No. 000-26321).
2.8
Agreement and Plan of Merger dated January 31, 2007, by and among Gasco Energy, Inc., Gasco Acquisition, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated September 20, 2006, filed September 21, 2006, File No. 001-32369).
2.9
First Amendment to Agreement and Plan of Merger dated January 31, 2007, by and between Gasco Energy, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated January 31, 2007, filed February 2, 2007, File No. 001-32369).
2.10
Second Amendment to Agreement and Plan of Merger dated January 31, 2007, by and among Gasco Energy, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated May 29, 2007, filed May 30, 2007, File No. 001-32369).
2.11
Third Amendment to Agreement and Plan of Merger dated October 22, 2007, by and between Gasco Energy, Inc. and Brek Energy Corporation (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K dated October 22, 2007, filed October 23, 2007, File No. 001-32369).
3.1
Amended and Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated December 31, 1999, filed on January 21, 2000, File No. 000-26321).
3.2
Certificate of Amendment to Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K/A dated January 31, 2001, filed on February 16, 2001, File No. 000-26321).
3.3
Certificate of Amendment to Articles of Incorporation dated June 21, 2005 (incorporated by reference to Exhibit 3.3 to the Company’s Form 10-Q/A for the quarter ended June 30, 2005, filed on August 9, 2005, File No. 001-32369).
3.4
Amended and Restated Bylaws of Gasco Energy, Inc., dated June 26, 2007 (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K dated June 26, 2007, filed on June 27, 2007, File No. 001-32369).
3.5
Certificate of Designation for Series B Convertible Preferred Stock (incorporated by reference to Exhibit 3.5 to the Company’s Form S-1 Registration Statement dated April 16, 2003, filed April 17, 2003, File No. 333-104592).
4.1
Form of Subscription and Registration Rights Agreement, dated as of August 14, 2002 between the Company and certain investors Purchasing Common Stock in August, 2002. (Filed as Exhibit 10.21 to the Company’s Form S-1 Registration Statement dated August 26, 2002, filed on August 27, 2002, File No. 333-98759).
4.2
Form of Gasco Energy, Inc. 8.00% Convertible Debenture, dated October 15, 2003 between each of The Frost National Bank, Custodian FBO Renaissance US Growth & Investment Trust PLC Trust No. W00740100, HSBC Global Custody Nominee (U.K.) Limited Designation No. 896414 and The Frost National Bank, Custodian FBO Renaissance Capital Growth & Income Fund III, Inc. Trust No. W00740000 (incorporated by reference to Exhibit 4.6 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).
4.3
Deed of Trust and Security Agreement, dated October 15, 2003 between Pannonian and BFSUS Special Opportunities Trust PLC, Renaissance Capital Growth & Income Fund III, Inc. and Renaissance US Growth & Income Trust PLC (incorporated by reference to Exhibit 4.7 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).
4.4
Subsidiary Guaranty Agreement, dated October 15, 2003 between Pannonian and Renn Capital Group, Inc (incorporated by reference to Exhibit 4.8 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).
4.5
Subsidiary Guaranty Agreement, dated October 15, 2003 between San Joaquin Oil and Gas, Ltd. And Renn Capital Group, Inc (incorporated by reference to Exhibit 4.9 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).
4.6
Form of Subscription and Registration Rights Agreement between the Company and investors purchasing Common Stock in October 2003 (incorporated by reference to Exhibit 4.10 to the Company’s Form 10-Q for the quarter ended September 30, 2003, filed on November 10, 2003, File No. 000-26321).
4.7
Form of Subscription and Registration Rights Agreement between the Company and investors purchasing Common Stock in February, 2004 (incorporated by reference to Exhibit 4.7 to the Company’s Form 10-K for the year ended December 31, 2003, filed on March 26, 2004, File No. 000-26321).
4.8
Indenture dated as of October 20, 2004, between Gasco Energy, Inc. and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 20, 2004, File No. 000-26321).
4.9
Form of Global Note representing $65 million principal amount of 5.5% Convertible Senior Notes due 2011 (incorporated by reference to Exhibit A to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on October 20, 2004, File No. 000-26321).
4.10
Registration Rights Agreement dated October 20, 2004, among Gasco Energy, Inc., J.P. Morgan Securities Inc. and First Albany Capital Inc (incorporate by reference to Exhibit 4.10 to the Company’s Form 10-Q for the quarter ended September 30, 2004 filed on November 12, 2004, File No. 000-26321).
4.11
Pledge and Security Agreement dated March 29, 2006 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC and JPMorgan Chase Bank, N.A. (incorporated by reference to Exhibit 4.2 to the Company’s Form 8-K dated March 29, 2006, filed March 30, 2006, File No. 001-32369).
4.12
Credit Agreement dated March 29, 2006 by and among Gasco Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton Oilfield Rentals, LLC, JPMorgan Chase Bank, N.A. and J.P. Morgan Securities Inc. (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K dated March 29, 2006, filed March 30, 2006, File No. 001-32369).
4.13
Voting Agreement dated September 20, 2006 by and among Gasco Energy, Inc., Richard N. Jeffs, Gregory Pek, Ian Robinson, Michael L. Nazmack, Eugene Sweeney and Shawne Malone (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K dated September 20, 2006, filed September 21, 2006, File No. 001-32369).
4.14
Underwriting Agreement dated April 9, 2007, between Gasco Energy, Inc. and JP Morgan Securities Inc. (incorporated by reference to Exhibit 1.1 to the Company’s Form 8-K dated April 9, 2007, filed April 13, 2007, File No. 001-32369).
# 10.1
1999 Stock Option Plan (incorporated by reference to Exhibit 4.1 to the Company’s Form 10-KSB for the fiscal year ended December 31, 1999, filed on April 14, 2000, File No. 000-26321).
# 10.2
Form of Stock Option Agreement under the 1999 Stock Option Plan (incorporated by reference to Exhibit 10.8 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
# 10.3
Stock Option Agreement dated January 2, 2001 between Gasco and Mark A. Erickson (Filed as Exhibit 10.9 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
# 10.4
Form of Stock Option Agreement between Gasco and each of the individuals named therein (incorporated by reference to Exhibit 4.6 to the Company’s Form S-8 Registration Statement (Reg. No. 333-122716), filed on February 10, 2005).
# 10.5
Michael Decker Amended and Restated Employment Contract dated February 14, 2003 (Filed as Exhibit 10.11 to the Company’s Form 10-K for the fiscal year ended December 31, 2002, filed on March 29, 2003, File No. 000-26321).
# 10.6
Mark A. Erickson Amended and Restated Employment Contract dated February 14, 2003 (Filed as Exhibit 10.12 to the Company’s Form 10-K for the fiscal year ended December 31, 2002, filed on March 29, 2003, File No. 000-26321).
# 10.7
Amended and Restated Consulting Agreement dated February 14, 2003, between Gasco and Marc Bruner (Filed as Exhibit 10.13 to the Company’s Form 10-K for the fiscal year ended December 31, 2002, filed on March 29, 2003, File No. 000-26321).
#10.8
2003 Restricted Stock Plan (Filed as Appendix B to the Company’s Proxy Statement dated August 25, 2003 for its 2003 Annual Meeting of Stockholders, filed on August 25, 2003, File No. 000-26321).
10.9
Muddy Creek Exploration Agreement dated August 15, 2001, between Gasco, Shama Zoe Limited Partnership and Burlington Oil and Gas Company (Filed as Exhibit 10.15 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
10.10
CD Exploration Agreement dated August 15, 2001, between Gasco, Shama Zoe Limited Partnership and Burlington Oil and Gas Company (Filed as Exhibit 10.16 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
10.11
Gamma Ray Exploration Agreement dated August 15, 2001, between Gasco, Shama Zoe Limited Partnership and Burlington Oil and Gas Company (Filed as Exhibit 10.17 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
10.12
Sublette County, WY AMI Agreement dated August 22, 2001 between Gasco, Alpine Gas Company and Burlington Oil and Gas Company (Filed as Exhibit 10.18 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
10.13
Lead Contractor Agreement dated January 24, 2002, between Gasco and Halliburton Energy Services, Inc. (Filed as Exhibit 10.19 to the Company’s Form 10-K for the fiscal year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).
10.14
Property Purchase Agreement, dated as of April 23, 2002, between the Company and Shama Zoe Limited Partnership (Filed as Exhibit 2.1 to the Company’s Form 8-K dated May 1, 2002, filed on May 9, 2002, File No. 000-26321).
10.15
Purchase Agreement, dated as of July 16, 2002, among the Company, Pannonian Energy Inc., San Joaquin Oil & Gas Ltd., Brek Energy Corporation, Brek Petroleum Inc., Brek Petroleum (California), Inc. and certain stockholders (Filed as Exhibit 2.1 to the Company’s Form 8-K dated July 16, 2002, filed on July 31, 2002, File No. 000-26321).
10.16
Amendment No. 1 to Property Purchase Agreement dated as of August 9, 2002 between the Company and Shama Zoe Limited Partnership. (Filed as Exhibit 10.22 to the Company’s Form S-1 dated August 15, 2002, filed on August 17, 2002, File No. 333-98759).
10.17
Financial Advisory Services Agreement dated August 22, 2002, between the Company and Energy Capital Solutions LLC. (Filed as Exhibit 10.23 to the Company’s Form S-1 dated August 16, 2002, filed on August 17, 2002 File No. 333-98759).
10.18
Termination and Settlement Agreement, dated as of December 23, 2004, among Gasco Energy, Inc., Marc A. Bruner and Mark A. Erickson (Filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 31, 2005, File No. 001-32369).
10.19
Joint Value Enhancement Agreement by and among Pannonian Energy Inc., M-I, LLC, Nabors Drilling USA, LP, Pool Well Services Co., Red Oak Capital Management LLC and Schlumberger Technology Corporation dated January 16, 2004 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 21, 2004, File No. 000-26321).
#10.20
Employment Agreement dated February 14, 2005 by and between Gasco Energy, Inc. and W. King Grant (incorporated by reference to Exhibit 4.2 to the Company’s Form 10-Q for the quarter ended March 31, 2006, filed May 5, 2006, File No. 001-32369).
10.21
Participation Agreement dated August 1, 2007 by and between Gasco Production Company and NFR Uinta Basin LLC (incorporated by reference to Exhibit 10.11 to the Company’s Form 10-Q for the quarter ended June 30, 2007, filed August 1, 2007, File No. 001-32369).
*23.1
Consent of Netherland, Sewell & Associates, Inc.
*23.2
Consent of Hein & Associates LLP
*31
Rule 13a-14(a)/15d-14(a) Certifications
*32
Section 1350 Certifications
*
Filed herewith.
#
Identifies management contracts and compensatory plans or arrangements.