ITEM 1 - BUSINESS
Business of Gasco
We are 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 activities in the Riverbend Project located in the Uinta Basin of northeastern Utah, targeting the Green River, Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations. As of December 31, 2009, we held interests in 282,326 gross acres (228,724 net acres) located in Utah, Wyoming, California and Nevada. As of December 31, 2009, we held an interest in 132 gross producing wells (77.6 wells, net to our interest) and three shut-in wells (3.0 net) located on these properties.
During 2009, we reached total depth on two gross operated wells (0.84 net), one of which was in progress at December 31, 2008, in the Riverbend Project. We spudded one new well during 2009 and upon reaching total depth on this well, we released our drilling rig. We conducted initial completion operations on two Upper Mancos wells and we re-entered three gross operated wells (0.92 net wells) to complete pay zones that were behind pipe. Additionally, we performed limited workover operations on certain Green River Formation oil wells to enhance oil production during the improved crude oil prices received during the last three quarters of 2009. As of December 31, 2009, we operated 132 gross producing wells. We currently have an inventory of 34 operated wells with up-hole completion potential and one well awaiting initial completion activities.
During June 2009, we sold our drilling rig for proceeds of $1,000,000 which consisted of a cash payment of $500,000 and an interest bearing promissory note of $500,000 with a maturity date of June 30, 2012. We recognized a loss of $905,850 on the sale which is recorded in “Loss on sale of assets, net” in the accompanying consolidated financial statements (see Note 2 “Significant Accounting Policies - Facilities and Equipment” of the accompanying consolidated financial statements).
We were incorporated on April 21, 1997 under the laws of the State of Nevada. We operated as a shell company until December 31, 1999.
Recent Developments
Sale of Gathering Assets
On February 26, 2010, we completed the sale (the “Closing”) of materially all of the assets (the “Asset Sale”) comprising our gathering system and our evaporative facilities, located in Uintah County, Utah (the “Gathering Assets”), to Monarch Natural Gas, LLC (“Monarch”) pursuant to an Asset Purchase Agreement dated January 29, 2010 (the “Purchase Agreement”). At Closing, we received total cash consideration of $23 million from Monarch, the entirety of which was used to repay amounts outstanding under our revolving credit facility.
Pursuant to the Purchase Agreement, simultaneous with Closing we entered into (i) a transition services agreement with Monarch pursuant to which we will provide certain services relating to the operation of the Gathering Assets to Monarch for a six-month term commencing at Closing; (ii) a gas gathering
agreement with Monarch pursuant to which we dedicated our natural gas production from all of our Utah acreage and Monarch will provide gathering, compression and processing services utilizing the Gathering Assets to us; and (iii) a salt water disposal services agreement with Monarch pursuant to which we may deliver salt water produced by our operations to the evaporative facilities that Monarch acquired in the Asset Sale. These agreements will result in less revenue and additional costs with an aggregate annual impact, inclusive of a reduction in depreciation expense, of approximately $3.5 million based on 2009 activity. The Purchase Agreement is subject to customary post-closing terms and conditions for transactions of this size and nature.
Acquisition of Petro-Canada Assets
On February 25, 2010, we completed the acquisition of two wells and certain oil and gas leases (the “Petro-Canada Assets”) from Petro-Canada Resources (USA) Inc., a Colorado corporation (“Petro-Canada”), for a purchase price of approximately $482,000, subject to customary post-closing terms and conditions for transactions of this size and nature. The sale was made pursuant to a definitive agreement dated February 4, 2010 by and between us and Petro-Canada. The Petro-Canada Assets include one producing well, one shut in well with recompletion potential and 5,582 gross and net acres located in Utah west of our Gate Canyons operating area. We funded this acquisition with cash flow from operating activities.
Amendment to Credit Facility
On February 1, 2010, our revolving credit facility was amended to, among other things, incrementally reduce our borrowing base by a fixed amount in connection with certain contemplated asset sales, including the sale of the Gathering Assets described above, and, effective as of April 1, 2010, to automatically reduce to $16 million, regardless of whether any of the contemplated asset sales were consummated. Effective February 26, 2010, in connection with the consummation of the Asset Sale and the application of the proceeds therefrom to pay down outstanding borrowings under our revolving credit facility, we elected to reduce the borrowing base to $16 million effective immediately. Following the $23 million debt repayment, our available credit is approximately $4.0 million.
Resignation of Former Chief Executive Officer; Appointment of Replacement
Effective January 27, 2010, our former Chief Executive Officer and President, Mark Erickson, resigned and was replaced by Charles Crowell as Chief Executive Officer and W. King Grant as President.
Principal Products or Services and Markets
We focus our 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 our sales have been to a few customers. The majority of our production was sold to one customer during each of the years ended December 31, 2009, 2008 and 2007: Anadarko Petroleum Corporation (“Anadarko”) during 2009 and 2008 and ConocoPhillips during 2007. However, we do not believe that the loss of a single purchaser, including Anadarko or ConocoPhillips, would materially affect our business because there are numerous other potential purchasers in the areas in which we sell our production. For the years ended December 31, 2009, 2008 and 2007, purchases by the following companies exceeded 10% of our total oil and gas revenues.
Rockies natural gas prices continued their lower trend during 2009. These low prices are due in part to weak demand resulting from a lower level of economic activity.
Competitive Business Conditions, Competitive Position in the Industry and Methods of Competition
Our natural gas and petroleum exploration, exploitation and production 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.
As discussed under “Item 1A
ITEM 1A. Risk Factors
Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. There may be additional risks that are not presently material or known. You should carefully consider each of the following risks and all other information set forth in this Annual Report on Form 10-K.
If any of the events described below occur, our business, financial condition, results of operations, liquidity or access to the capital markets could be materially adversely affected. In addition, the current global economic environment intensifies many of these risks.
Future economic conditions in the US and key international markets may materially adversely impact our operating results.
The US and other world economies are slowly recovering from a recession which began in 2008 and extended into 2009. Growth has resumed, but is modest. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced in recent years. In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate will result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.
We have incurred losses and may continue to incur losses in the future.
Historically, other than for the year ended December 31, 2008, we have generated losses which have not provided sufficient cash flows to provide working capital for our ongoing overhead, the funding of our lease acquisitions and the exploration and development of our properties. As such, and in light of the current economic environment and commodity price levels, we may not be able to successfully develop any prospects that we have or acquire without adequate financing and we may not achieve profitability from operations in the near future or at all.
During the years ended December 31, 2009 and 2007, we incurred a net loss of $50,188,171 and $104,373,921, respectively. As of December 31, 2009, we had an accumulated deficit of $225,401,140. 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 business, financial condition and results of operations.
Oil and natural gas prices are volatile. The extended decline in commodity prices has adversely affected, and in the future will adversely affect, our financial condition and results of operations, cash flows, access to the capital markets, and ability to grow.
Our financial condition, operating results, and future rate of growth depend upon the prices that we receive for our oil and natural gas. Prices also affect our cash flow available for capital expenditures and our ability to access funds under our revolving credit facility and through the capital markets. The amount available for borrowing under our revolving credit facility is subject to a borrowing base, which is determined by our lenders taking into account our estimated proved reserves and is subject to scheduled periodic redeterminations, as well as unscheduled discretionary redeterminations, based on pricing models and other economic assumptions determined by the lenders at such time. Effective February 26, 2010, our borrowing base under our revolving credit agreement was reduced to $16 million from $35 million. The decline in oil and natural gas prices has adversely affected the value of our estimated proved reserves and, in turn, the pricing assumptions used by our lenders to determine our borrowing base. If
commodity prices remain at current levels or decline in 2010, it will have similar adverse effects on our reserves and global borrowing base. Further, because we have elected to use the full-cost accounting method, we must perform each quarter a “ceiling test” that is affected by declining prices. Significant price declines could cause us to take one or more ceiling test write-downs, which would be reflected as non-cash charges against current earnings. During the first quarter of 2009, we recorded an impairment of $41,000,000.
In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas that we can produce economically. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth. We intend to fund our 2010 capital expenditures budget from cash flows generated from operations in anticipation of continuing current or declining commodity prices.
The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future. Oil spot prices reached historical highs in July 2008, peaking at more than $145 per barrel, and natural gas spot prices reached near historical highs in July 2008, peaking at more than $13 per MMBtu. These prices have declined significantly since that time and may continue to fluctuate widely in the future, either collectively or independent of one another, in response to a variety of additional factors that are beyond our control, such as:
•
changes in global supply and demand for natural gas and oil;
•
commodity processing, gathering and transportation availability;
•
domestic and global political and economic conditions;
•
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
•
weather conditions, including hurricanes;
•
technological advances affecting energy consumption;
•
an increase in alternative fuel sources;
•
higher fuel taxes and other regulatory actions;
•
an increase in fuel economy;
•
additional domestic and foreign governmental regulations; and
•
the price and availability of alternative fuels.
Lower natural gas and oil prices may not only decrease our revenue, 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 2009, the previous oil and gas reserves quantities decreased by approximately 6% primarily due to the decrease in gas prices used to estimate reserve quantities, from $4.63 per mcf at December 31, 2008 to $2.85 per mcf
at December 31, 2009. This decrease in reserve quantities was partially offset by an increase in the oil price from $15.33 per bbl at December 31, 2008 to $44.46 per bbl at December 31, 2009. The price per barrel of oil reflects our blend of oil and condensate. If the prices for oil and gas decrease materially from year end 2009 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 receiving are at a discount to gas prices in other parts of the country. Additional factors that can cause price volatility for crude oil and natural gas within this region are:
•
the availability of gathering systems with sufficient capacity to handle local production;
•
seasonal fluctuations in local demand for production;
•
local and national gas storage capacity;
•
interstate pipeline capacity; and
•
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.
We may not be able to maintain adequate cash flow from operations or obtain adequate financing to grow our operations.
We will require significant additional capital to fund our future drilling activities and to meet our future debt maturities. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to service our indebtedness or achieve our planned growth and operating results. We have relied in the past primarily on the sale of equity capital, the issuance of equity, borrowings under our revolving credit facility and farm-out and other similar types of transactions to fund working capital and the acquisition of our prospects and related leases. Issuing equity securities to satisfy our financing requirements could cause substantial dilution to our stockholders. Failure to generate operating cash flow or to obtain additional financing for the development of our properties 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.
During the fourth quarter of 2008 and through 2009, the severe disruptions in the credit markets and reductions in global economic activity had significant adverse impacts on stock markets and oil and gas-related commodity prices, which contributed to a significant decline in the our stock price and negatively impacted our liquidity. We expect our liquidity will continue to be negatively affected in 2010 by the effects of this activity. 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 oil and gas exploration and production activities beyond our planned recompletion activities, including those reflected in our 2010 budget. Effective February 26, 2010, our borrowing base under our revolving credit facility was reduced to $16 million from $35 million and as of March 3, 2010, we had $11.5 million of outstanding borrowings thereunder. Our borrowing base could be further reduced in the future by our lenders. Though we anticipate funding our capital budget of $6 million for 2010 through cash flows from operations, an inability to access additional borrowings in excess of our existing $4 million of existing capacity under
our revolving credit agreement will limit our ability to increase our operating budget and execute on our growth plans. The maturity of our revolving credit facility and our outstanding $65 million 5.50% Convertible Senior Notes occur in March and October of 2011, respectively. The lenders under our revolving credit facility may elect not to extend the maturity of such facility without our having previously refinanced, restructured or repaid the 5.50% Convertible Senior Notes due 2011. Accordingly, an inability to refinance, restructure or repay such convertible notes prior to their maturity on terms acceptable to us may impair our ability to execute on future growth plans. Furthermore, the failure to refinance, restructure or repay such convertible notes or our revolving credit facility prior to their maturities may impair our ability to obtain alternate sources of financing. Any refinancing, restructuring or repayment could cause substantial dilution to our stockholders either through the issuance of additional equity or the sale of assets.
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. Additionally, should our obligation to repay indebtedness under our revolving credit facility be accelerated, we would be in default under the indenture governing our 5.50% Convertible Senior Notes due 2011, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such convertible notes. Similarly, should our obligation to repay indebtedness under our convertible notes be accelerated, we would be in default under our revolving credit facility, which would require repayment of the outstanding principal, interest and any other amounts then due.
Lower oil and natural gas prices could negatively impact our ability to borrow. Additionally, availability under our revolving credit facility is based on a borrowing base which is subject to redetermination by our lenders. If our borrowing base is reduced, we may be required to repay amounts outstanding under our revolving credit facility.
Our revolving credit facility limits our borrowings to the borrowing base less our total outstanding letters of credit issued thereunder. As of December 31, 2009, our borrowing base was $35.0 million and our outstanding letter of credit sublimit was $10.0 million. In February 2010, our borrowing base decreased to $16 million. Under the terms of our revolving credit facility, our borrowing base is subject to semi-annual redetermination by our lenders based on their valuation of our proved reserves and their internal criteria. In addition to such semi-annual determinations, our lenders may request one additional borrowing base redetermination between each semi-annual calculation. Our next borrowing base redetermination is scheduled for May 2010. If our borrowing base is further reduced as a result of a redetermination, we may be required to repay an additional portion of our outstanding borrowings and will have less access to borrowed capital going forward. If we do not have sufficient funds on hand for repayment, we may be required to seek a wavier or amendment from our lenders, refinance our revolving credit facility or sell assets or additional shares of common stock. We may not be able obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to make the required repayment could result in a default under our revolving credit facility, which could adversely affect our business, financial condition and results or operations. Additionally, should our obligation to repay indebtedness under our revolving credit facility be accelerated, we would be in default under the indenture governing our 5.50% Convertible Senior Notes due 2011, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such convertible notes. Please read “Item 7. Management’s Discussion and Analysis of Financial Position and Results of Operations - Liquidity and Capital Resources - Credit Facility.”
Our revolving credit facility imposes restrictions on us that may affect our ability to successfully operate our business.
Our revolving credit facility imposes certain operational and financial restrictions on us that limit our ability to:
•
incur additional indebtedness;
•
create liens;
•
sell our assets to, or consolidate or merge with or into, other companies;
•
make investments and other restricted payments, including dividends; and
•
engage in transactions with affiliates.
Our revolving credit facility contains covenants that require us to maintain (1) a current ratio (defined as current assets plus unused availability under the revolving credit facility divided by current liabilities excluding the current portion of the revolving 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 four quarters not to be greater than 3.5:1 for each fiscal quarter. In addition, the revolving 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. As of December 31, 2009, our current and senior debt to EBITDAX ratios were 2.9:1 and 2.3:1, respectively, and we were in compliance with each of the covenants as of December 31, 2009. Any failure to be in compliance with any material provision or covenant of our revolving credit facility could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under our revolving credit facility. Additionally, should our obligation to repay indebtedness under our revolving credit facility be accelerated, we would be in default under the indenture governing our 5.50% Convertible Senior Notes due 2011, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such convertible notes. Sustained or lower oil and natural gas prices could reduce our consolidated EBITDAX and thus could reduce our ability to maintain existing levels of senior debt or incur additional indebtedness. Sustained or lower oil and natural gas prices may make it more difficult for us to satisfy this ratio in future quarters. To the extent it becomes necessary to address any anticipated covenant compliance issues, we may be required to sell a portion of our assets or issue additional securities, which would be dilutive to our shareholders. Given the condition of current credit and capital markets, any sale of assets or issuance of additional securities may not be on terms acceptable to us.
The restrictions under our revolving credit facility 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. Any failure to remedy any event of default could have a material adverse effect on our business, financial condition or results of operations.
A failure by the gatherer of our natural gas to perform its obligations under our gas gathering agreement may negatively affect our ability to deliver our natural gas production for sale.
Pursuant to the gas gathering agreement, we rely on Monarch to gather, process, compress and deliver our natural gas production from wellheads to points of sale. Additionally, pursuant to the gas gathering agreement, Monarch is required to connect to the gathering system future wells that we drill within an area of mutual interest established thereunder. Any failure by Monarch or any successor thereto to timely
perform its obligations under the gas gathering agreement may limit our ability to deliver production into the interstate pipeline where it is sold. A delay or reduction in the amount of natural gas that we sell as a result of a failure by Monarch to timely perform such obligations or a delay or failure to connect future wells to the gathering system could have a material adverse effect on our business, financial condition or results of operations.
Pipeline constraints may limit our ability to sell production and may negatively affect the price at which we sell our production.
Our production is transported through a single interstate pipeline. Any constraints on the capacity of this pipeline could adversely affect our ability to sell production and, in certain circumstances, may limit our ability to sell any or all of our 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 we are able to sell the production that does flow. A reduction in the amount of natural gas that we can sell or the price at which such natural gas can be sold could have a material adverse effect on our business, financial condition or results of operations.
Our estimates of proved reserves have been prepared under new SEC rules that went into effect for fiscal years ending on or after December 31, 2009, which may make comparisons to prior periods difficult and could limit our ability to book additional proved undeveloped reserves in the future.
This Annual Report on Form 10-K presents estimates of our proved reserves as of December 31, 2009, which have been prepared and presented under new SEC rules. These new rules are effective for fiscal years ending on or after December 31, 2009, and require SEC reporting companies to prepare their reserves estimates using revised reserve definitions and revised pricing based on twelve-month unweighted first-day-of the-month average pricing. The previous rules required that reserve estimates be calculated using last-day-of the-year pricing. As a result of these changes, direct comparisons to our previously-reported reserves amounts may be more difficult.
Another impact of the new SEC rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This new rule has limited and may continue to limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill on those reserves within the required five-year timeframe.
The SEC has not reviewed our or any reporting company’s reserve estimates under the new rules and has released only limited interpretive guidance regarding reporting of reserve estimates under the new rules and may not issue further interpretive guidance on the new rules. Accordingly, while the estimates of our proved reserves at December 31, 2009 included in this report have been prepared based on what we and our independent reserve engineers believe to be reasonable interpretations of the new SEC rules, those estimates could differ materially from any estimates we might prepare applying more specific SEC interpretive guidance.
Our proved reserves are estimates and depend on many assumptions. Any material inaccuracies in these assumptions could cause the quantity and value of our oil and gas reserves, and our revenue, profitability, and cash flow, to be materially different from our estimates.
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. Please see “Our estimates of proved reserves have been prepared under new SEC rules that went into effect for fiscal years ending on or after December 31, 2009, which may make comparisons to prior periods difficult and could limit our ability to book additional proved undeveloped reserves in the future.” The accuracy of a reserve estimate is a function of:
•
the quality and quantity of available data;
•
the interpretation of that data;
•
the accuracy of various mandated economic assumptions; and
•
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 nine years as of December 31, 2009, 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, 2009. 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.
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 the unweighted arithmetic average of the first day of the month commodity prices for the trailing twelve months and development and production costs on the date of estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.
Lower oil and gas prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.
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 the twelve month trailing average first of month 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. During February 2010, we sold our gathering assets and entered into a gathering agreement with the purchaser. As a result, our gathering expenses will increase which we expect will lower the value of our reserves in the future. This reduction in reserve value may cause us to record a future impairment of our proved properties.
As of March 31, 2009, our full cost pool exceeded the ceiling limitation based on oil and gas prices of $34.40 per barrel and $2.36 per Mcf by $41,000,000. Therefore, impairment expense of $41,000,000 was recorded during the year ended December 31, 2009.
Investments in unproved properties with a carrying value of approximately $38,600,000 as of December 31, 2009, including capitalized interest costs, are also assessed periodically to ascertain whether impairment has occurred. Impairments in such properties may result from lower commodity prices, expiration of leases, inability to find partners, inadequate financing or unsuccessful drilling results. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. The amount of impairment assessed, if any, is added to the costs to be amortized, or is reported as a period expense, as appropriate. If an impairment of unproved properties results in a reclassification to proved oil and gas properties, the ceiling test cushion would be reduced.
During 2009 we reclassified approximately $1,100,000 and $200,000 of expiring acreage costs primarily in Utah and California, respectively into proved property. This acreage represents the leases that will expire during 2010 before we are able to develop them further.
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.
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 23 to 24 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 60 days. 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.
Our drilling operations may be delayed or revised unless we receive approval of our Environmental Impact Statement.
As we continue to develop our Utah acreage, we are required to file an Environmental Impact Statement under the National Environmental Policy Act. Any delay of approval or mandated change to our plan of development may materially delay our ability to drill on our acreage in Utah or may require us to make additional capital investments or make certain areas of our acreage inaccessible to drilling. Any delay of or restriction on our ability to drill on our acreage in Utah could materially and adversely affect our future business, financial condition and results of operations.
We may have difficulty managing any 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. If 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.
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. 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 do not believe that our competitive position in the petroleum and natural gas industry is significant.
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 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.
Our operations may incur substantial liabilities to comply with climate change legislation and regulatory initiatives.
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is considering legislation to reduce emissions of greenhouse gases and more than one-third of the states, either individually or through multi-state initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. Also, the U.S. Supreme Court’s holding in its 2007 decision, Massachusetts, et al. v. EPA, that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act could result in future regulation of greenhouse gas emissions from stationary sources, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business or demand for the natural gas we produce.
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.
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.
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. Economically hedging the commodity price 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, 2009 was a current liability of $1,932,513 and a non-current liability of $761,092. See “Item 7A - Quantitative and Qualitative Disclosures about Market Risk” for further discussion. In addition, our commodity price risk management transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
•
production is less than expected;
•
the counterparty to the contract defaults on its obligations; or
•
there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.
In addition, economic hedging may limit the benefit we would otherwise receive from increases in the prices of oil and gas.
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. Grant, our President and Chief Financial Officer and Mr. Decker, our Executive Vice President and Chief Operating Officer - could have a material adverse effect on our business, financial condition and results of operations. We have not obtained “key man” insurance for any of our management.
Our directors are engaged in other businesses which may result in conflicts of interest.
Certain of our directors also serve as directors of other companies or have significant shareholdings in other companies operating in the oil and gas industry. Our Chairman, Marc A Bruner, is the largest shareholder of Petrohunter Energy Corporation (Petrohunter) and Exxcel Energy. Mr. Bruner also serves as a Director and is the Chief Executive Officer of Falcon Oil and Gas, Ltd (Falcon) Falcon operations and projects are in Hungary, Australia, and South Africa. Another of our directors, C. Tony Lotito, currently serves as the Executive Vice President Business Development of Falcon Oil and Gas, Ltd and serves as a member of the Board of Directors of Petrohunter Energy Corporation. Charles Crowell, one of our directors, is currently serving as our Chief Executive Officer and also serves on the Board of Directors of Derek Oil & Gas Corporation. Richard S. Langdon, another one of our 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 the Chief Executive Officer of Sigma Energy Ventures with E&P activities in the Texas Gulf Coast. 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 and in the Cherokee Basin in Oklahoma and Kansas. Richard Burgess, another director, serves on the Board of Michigan Oil and Gas Association. We estimate that all of our outside directors spend up to 10% of their time on our business.
To the extent that such other companies participate in ventures in which we 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, our directors are required to act honestly and in good faith with a view to our best interests. In determining whether or not we 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 we may be exposed and our 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.
One of our directors resides outside the United States and maintains a substantial portion of his 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.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
President Obama’s Proposed Fiscal Year 2011 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain
key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.
The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.
On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, the EPA had proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of greenhouse gases from motor vehicles and that could also lead to the imposition of greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil, natural gas and NGLs that we produce.
Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and the Obama Administration has indicated its support of legislation to reduce greenhouse gas emissions through an emission allowance system.
Although it is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil, natural gas and NGLs that we produce.
Even if such legislation is not adopted at the national level, more than one-third of the states, either individually or as part of regional initiatives, have begun taking actions to control and/or reduce emissions
of greenhouse gases, as have a number of local governments. Although most of the regional and state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as coal-fired electric power plants, smaller sources of emissions could become subject to greenhouse gas emission limitations, allowance purchase requirements or other restrictions or costs. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.
Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.
The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.
Congress currently is considering broad financial regulatory reform legislation that among other things would impose comprehensive regulation on the over-the-counter (OTC) derivatives marketplace and could affect the use of derivatives in hedging transactions. The financial regulatory reform bill adopted by the House of Representatives on December 11, 2009, would subject swap dealers and “major swap participants” to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also would require central clearing for transactions entered into between swap dealers or major swap participants. For these purposes, a major swap participant generally would be someone other than a dealer who maintains a “substantial” net position in outstanding swaps, excluding swaps used for commercial hedging or for reducing or mitigating commercial risk, or whose positions create substantial net counterparty exposure that could have serious adverse effects on the financial stability of the U.S. banking system or financial markets. The House-passed bill also would provide the Commodity Futures Trading Commission (CFTC) with express authority to impose position limits for OTC derivatives related to energy commodities. Separately, in late January, 2010, the CFTC proposed regulations that would impose speculative position limits for certain futures and option contracts in natural gas, crude oil, heating oil, and gasoline. These proposed regulations would make an exemption available for certain bona fide hedging of commercial risks. Although it is not possible at this time to predict whether or when Congress will act on derivatives legislation or the CFTC will finalize its proposed regulations, any laws or regulations that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or
increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.
Risks Related to Our Capital Stock
If we cannot meet the NYSE AMEX’s continued listing requirements, the NYSE Amex may delist our common stock, which would have an adverse impact on the liquidity and market price of our common stock.
Our common stock is currently listed on the NYSE Amex, LLC (the “NYSE Amex”). On June 25, 2009, we received a notice from the NYSE Amex LLC (“NYSE Amex”), dated June 25, 2009, informing us that we did not meet certain of the continued listing standards of the NYSE Amex. Specifically, the notice stated that we were not in compliance with Section 1003(a)(i) of the NYSE Amex Company Guide, with stockholders’ equity of less than $2,000,000 and net losses in two of its three most recent fiscal years; and Section 1003(a)(ii) of the NYSE Amex Company Guide, with stockholders’ equity of less than $4,000,000 and net losses in three of its four most recent fiscal years. The notice also stated that in order to maintain its listing, we must submit a plan of compliance to the NYSE Amex by July 27, 2009 that addresses how we intend to regain compliance with Sections 1003(a)(i) and 1003(a)(ii) of the NYSE Amex Company Guide by December 27, 2010.
We submitted our plan to the NYSE Amex on July 27, 2009, and provided supplemental information on August 25, 2009, advising the NYSE Amex of the actions we have taken, and plan to take, to attempt to bring the Company into compliance with the applicable listing standards by December 27, 2010.
By letter dated September 15, 2009, the NYSE Amex notified us that it had accepted our plan and determined that, in accordance with Section 1009 of the NYSE Amex Company Guide, we had made a reasonable demonstration of our ability to regain compliance with Section 1003(a)(i) and 1003(a)(ii) of the NYSE Amex Company Guide by December 27, 2010. The NYSE Amex granted us an extension until December 27, 2010 (the “extension period”) to regain compliance with the continued listing standards of the NYSE Amex Company Guide. Our listing on the NYSE Amex is being continued pursuant to this extension through the extension period subject to certain conditions.
We will be subject to periodic review by the NYSE Amex during the extension period. There can be no assurance that we will be able to achieve compliance with Sections 1003(a)(i) and 1003(a)(ii) of the NYSE Amex Company Guide within the required time frame. If we are not able to make progress consistent with our plan or to regain compliance with the continued listing standards by the end of the extension period, we will be subject to delisting procedures as set forth in the NYSE Amex Company Guide. A delisting of our common stock could negatively impact us by reducing the liquidity and market price of our common stock and the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing.
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;
•
an inability to regain compliance with the listing requirements of the NYSE AMEX; 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, 2009, we had 107,715,897 shares of common stock issued and outstanding and outstanding options to purchase an additional 12,096,672 shares of common stock. Additional options may be granted to purchase 1,275,918 shares of common stock under our stock option plan and an additional 326,750 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 adjusts 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 123,965,897 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 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 116,444 gross acres in the Uinta Basin of northeastern Utah, of which we hold interests in approximately 80,944 net acres as of December 31, 2009. Historically, our engineering and geologic focus has been concentrated on three tight-sand formations in the Uinta basin: the Wasatch, Mesaverde, Mancos 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 2009, we reached total depth on 2 gross wells (approximately 0.84 net wells), one of which was in progress at December 31, 2008, in the Riverbend area. We spudded one new well during 2009 and upon reaching total depth on this well, we released our remaining drilling rig. We did not conduct any initial completion operations. We re-entered three gross operated wells (0.92 net wells) to complete pay zones that were behind pipe. Additionally, we performed limited workover operations on certain Green River Formation oil wells to enhance oil production during the improved oil prices received during the last three quarters of 2009. As of December 31, 2009, we operated 132 gross producing wells. We currently have an inventory of 34 operated wells with up-hole recompletion opportunities and one Upper Mancos well awaiting initial completion activities.
Based on current expectations, we intend to fund our 2010 capital expenditure program entirely through cash flow from operations. This program will focus primarily on completion and recompletion projects on our existing wells. Consequently, we will monitor spending and cash flow throughout the year and may accelerate or delay investment depending on commodity prices, cash flow expectations and changes in our borrowing capacity. During 2009 we reclassified approximately $1,100,000 and $200,000 of expiring acreage primarily in Utah and California, respectively into proved property. This acreage represents the leases that will expire during 2010 before we are able to develop it further.
On February 26, 2010, we completed the sale (the “Closing”) of materially all of the assets (the “Asset Sale”) comprising our gathering system and our evaporative facilities, located in Uintah County, Utah (the “Gathering Assets”), to Monarch Natural Gas, LLC (“Monarch”) pursuant to an Asset Purchase Agreement dated January 29, 2010 (the “Purchase Agreement”). At Closing, we received total cash consideration of $23 million from Monarch, the entirety of which was used to repay amounts outstanding under our revolving credit facility.
Pursuant to the Purchase Agreement, simultaneous with Closing we entered into (i) a transition services agreement with Monarch pursuant to which we will provide certain services relating to the operation of the Gathering Assets to Monarch for a six-month term commencing at Closing; (ii) a gas gathering agreement with Monarch pursuant to which we dedicated our natural gas production from all of our Utah acreage and Monarch will provide gathering, compression and processing services utilizing the Gathering Assets to us; and (iii) a salt water disposal services agreement with Monarch pursuant to which we may deliver salt water produced by our operations to the evaporative facilities that Monarch acquired in the Asset Sale. These agreements will result in less revenue and additional costs with an aggregate annual impact, inclusive of a reduction in depreciation expense, of approximately $3.5 million based on 2009
activity. The Purchase Agreement is subject to customary post-closing terms and conditions for transactions of this size and nature.
On February 25, 2010, we completed the acquisition of certain oil and gas leases and lands (the “Petro-Canada Assets”) from Petro-Canada Resources (USA) Inc., a Colorado corporation (“Petro-Canada”), for a purchase price of approximately $482,000, subject to customary post-closing terms and conditions for transactions of this size and nature. The sale was made pursuant to a definitive agreement dated February 4, 2010 by and between us and Petro-Canada. The Petro-Canada Assets include one producing well, one shut-in well with recompletion potential and 5,582 gross and net acres located in Utah west of our Gate Canyon operating area. We funded this acquisition with cash flow from operating activities.
Greater Green River Basin Project
As of December 31, 2009, we had a leasehold interest in approximately 25,124 gross (14,908 net) acres in the Greater Green River Basin area of Wyoming. The acreage covers two prospects identified by us.
The low natural gas prices in this area has made it difficult for us to find partners to participate in the drilling of wells in this area and as a result, we reclassified all unproved leasehold costs associated with this area into proved property during 2007. We currently have no plans to develop this acreage.
Southern California Project
As of December 31, 2009, we had a leasehold interest in approximately 24,996 gross acres (18,492 net acres) in Kern and San Luis Obispo Counties of Southern California. On one of our prospects in Kern County, we entered into a farm-out agreement with a large exploration and production company who has a considerable California operations presence. We received a prospect fee and will be carried for a 20% working interest on the initial well and will turn over operations on the prospect to our partner. The operator has the option to drill a second well in which we will be carried for a 20% working interest.
We have entered into agreements and currently receive prospect fees and working interests on three of our California prospects.
In one of our prospects in the San Joaquin Basin of Southern California, exploratory drilling commenced during the fourth quarter of 2009. In mid-December, total depth of 2,400 feet was reached on this non-operated well in which we have a 33.3% carried working interest. The well encountered oil shows but not in quantities deemed economic to produce and this well was plugged and abandoned. We did not incur any exploration expense or dry well costs on this well. We are currently in discussions with the operator to determine how best to proceed in this area. The operator has approximately 150 days to propose another test well in which we will be carried for a 33.3% working interest.
Nevada Project
As of December 31, 2009 we had a leasehold interest in approximately 115,762 gross (114,380 net acres) in eleven prospects within White Pine and Elko Counties Nevada. Two wells were drilled in this area during 2007, both were dry wells. 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.
Oil and Natural Gas Reserves
In December 2008, the SEC adopted new rules related to modernizing reserve calculation and disclosure requirements for oil and natural gas companies, which became effective prospectively for annual reporting periods ending on or after December 31, 2009. The new rules expand the definition of oil and gas producing activities to include the extraction of saleable hydrocarbons from oil sands, shale, coal beds or other nonrenewable natural resources that are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. The use of new technologies is now permitted in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Other definitions and terms were revised, including the definition of proved reserves, which was revised to indicate that entities must use the average of beginning-of-the-month commodity prices over the preceding 12-month period, rather than the end-of-period price, when estimating whether reserve quantities are economical to produce. Likewise, the 12-month average price is now used to calculate cost center ceilings for impairment and to compute depreciation, depletion and amortization. Another significant provision of the new rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking.
Accordingly, our estimated proved reserves and related future net revenues, PV-10 and Standardized Measure at December 31, 2009 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January 2009 through December 2009, without giving effect to derivative transactions, and were held constant throughout the life of the properties. These prices, weighted by production over the lives of the proved reserves were $44.46 for oil and oil equivalents and $2.85 for gas. We do not believe that it is practicable to estimate the effect of applying the new rules for the changes in reserve quantities or the standardized measure of discounted cash flows for the year ended December 31, 2009.The amendments to the definition of oil and gas producing activities did not have an impact on our total proved reserves as of December 31, 2009.
Company Reserve Estimates
Our proved reserve information as of December 31, 2009 included in this Annual Report on Form 10-K was estimated by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. A copy of NSAI’s summary reserve report is included as Exhibit 99.1 to this Annual Report on Form 10-K. See Note 20 “Supplemental Oil and Gas Reserve Information (Unaudited)” to the accompanying consolidated financial statements for further discussion. In accordance with SEC guidelines, NSAI’s estimates of future net revenues from our properties, and the PV-10 and standardized measure thereof, were determined to be economically producible under existing economic conditions, which requires the use of the 12-month average price for each product, calculated as the unweighted arithmetic average of the first-day-of-the-month price for the period January 2009 through December 2009, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations.
The tables below set forth information as of December 31, 2009 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 (“PV-10”) nor the after-tax standardized measure is intended to represent the current market value of the estimated oil and natural gas reserves we own. The average prices weighted by production over the lives of the proved reserves used in the reserve report were $2.85 per Mcf of gas and $44.46 per bbl of oil. All of our proved undeveloped reserves became uneconomic at these prices and as a result were not included in the December 31, 2009 reserve estimates.
All of our 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 the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January 2009 through December 2009, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The average prices weighted by production over the lives of the proved reserves used in the reserve report were of $2.85 per Mcf of gas and $44.46 per bbl of oil. All of our proved undeveloped reserves became uneconomic at these prices and as a result were not included in the December 31, 2009 reserve estimates. These prices should not be interpreted as a prediction of future prices. During February 2010, we closed the sale of our gathering assets and entered into a gathering agreement with the purchaser. As a result, the gathering fees used in future reserve reports will increase and the present value of discounted future net cash flows are expected to decrease.
Reserve engineering is a subjective process of estimating underground accumulations of crude oil, condensate and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may differ from those assumed in these estimates. Therefore, the PV-10 amounts shown above should not be construed as the current market value of the oil and natural gas reserves attributable to our properties.
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. As of December 31, 2009, the present value of discounted future net cash flows and the standardized measure of discounted future net cash flows are equal because the effects of estimated future income tax expenses are zero.
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process.
The technical persons at NSAI responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers
We also maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI to ensure the integrity, accuracy and timeliness of data furnished to NSAI in their reserves estimation process. In the fourth quarter, our technical team meets regularly with representatives of NSAI to
review properties and discuss methods and assumptions used in NSAI’s preparation of the year-end reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary copy of the NSAI reserve report is reviewed by our audit committee with representatives of NSAI and internal technical staff. Additionally, our senior management reviews and approves any internally estimated significant changes to our proved reserves on a quarterly basis.
Reserve Technologies.
Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, NSAI employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps and available down well and production data, seismic data, well test data.
Reserve Sensitivities
The following table discloses information regarding the sensitivity of our estimated total proved oil and gas reserves to price fluctuations.
(a)
This case represents pricing under SEC rules under which he prices used are the 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period January 2009 through December 2009 The oil and gas prices used in this scenario, weighted by production over the lives of the proved reserves are $44.46 per bbl of oil and $2.85 per Mcf of gas.
(b)
Scenario 1 estimates total proved reserves assuming a 10% price increase in both the oil and the gas price used in the SEC pricing scenario.
(c)
Scenario 2 estimates total proved reserves assuming a 10% price decrease in both the oil and the gas price used in the SEC pricing scenario.
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
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 Oil and Gas Wells
The following summarizes the Company’s productive and shut-in oil and gas wells as of December 31, 2009.
As of December 31, 2009, we operated 132 gross (77.6 net to our interest) producing wells and 3 gross (3 net) shut-in wells located on these properties.
Oil and Gas Acreage
The following table sets forth our undeveloped and developed leasehold acreage, by area as of December 31, 2009. The table does not include acreage that we have a contractual right to acquire or to earn through drilling projects, or any other acreage for which we have not yet received leasehold assignments. In certain leases, our 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 our 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, 2009, approximately 82% of the gross acreage that we hold is located on federal lands and approximately 17% of the acreage is located on state lands. It has been our 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. We have generally been able to obtain state permits within 60 days, while obtaining federal permits has taken approximately 24 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 our acreage located on federal lands is delayed significantly by the permitting process, we may have to operate at a loss for an extended period of time. Such delays could result in impairments of the carrying value of our unproved properties and could impact the ceiling test calculation. The aggregate carrying value of our unproved acreage is approximately $38,600,000 as of December 31, 2009.
Drilling Activity
The following table sets forth our drilling activity during the years ended December 31, 2009, 2008 and 2007.
Office Space
We lease approximately 11,843 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 $151,200 per year. During February 2010, we extended our current lease through May 31, 2011 at an annual rate of approximately $165,600.
ITEM 3
ITEM 3 - LEGAL PROCEEDINGS
EPA Enforcement Action
In early 2007, a consultant to Riverbend Gas Gathering, LLC (“Riverbend”), a wholly owned subsidiary of the Company, who 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 Riverbend 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 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. Riverbend’s June 22 letter voluntarily disclosed the potential violations to 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 has continued to work with the EPA and the Department of Justice on a settlement of this matter, and it anticipates that such a resolution will be achieved during 2010. Although we are unable to estimate a range of possible costs, we believe 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 our capital budget, and that any civil penalty that may be assessed in conjunction with a resolution of this matter will not materially affect our financial position or liquidity. The compliance costs could, however, materially affect our results of operations for a particular period.
Brek Litigation
On December 5, 2008, a lawsuit was filed in state court in Cook County, Illinois (“Sweeney litigation”) by eleven individual plaintiffs and Griffin Asset Management, LLC. The lawsuit alleges that defendants Richard N. Jeffs (“Jeffs), Marc Bruner (“Bruner”) and the Company through its agency with Bruner, made misrepresentations, committed fraud, aided and abetted a scheme to defraud, and conspired to defraud in connection with the plaintiffs’ investment in Brek Energy Corporation (“Brek”). The complaint alleges that plaintiffs’ relied on various misrepresentations and omissions by the individual defendants when making the decision to invest in Brek, which merged into the Company in December of 2007. Plaintiffs sought unspecified damages in an amount in excess of $50,000, punitive damages, attorneys’ fees, and costs. The Company removed the case to the United States District Court for the Northern District of Illinois, Eastern Division, on January 7, 2009 and answered the complaint, denying all liability, on February 13, 2009. A scheduling conference was held on April 1, 2009. The judge ordered fact discovery in the case to be completed by December 15, 2009 and set the trial for June 7, 2010. Following the scheduling conference, Jeffs was served with the complaint and filed a motion to dismiss all counts against him on the grounds that certain claims are barred by limitations, that plaintiffs lack standing to bring other claims, and that plaintiffs have failed to join an indispensable party (Brek).
During the fall of 2009, the parties began to engage in the early stages of discovery and numerous depositions were scheduled for late November and the first half of December, 2009. Prior to the start of depositions, however, on November 25, 2009, the parties reached an agreement in principle to settle the claims made against the Company and Bruner in the Sweeney litigation.
On December 4, 2009, while counsel for the Company was documenting the partial settlement, counsel for Jeffs sent a letter to the Company demanding that the Company (1) reimburse Jeffs for his defense costs to date in the Sweeney litigation; and (2) indemnify Jeffs for any judgment entered (or settlement made) in the Sweeney litigation. Jeffs’ counsel claimed that Jeffs was entitled to such reimbursement and indemnification under the bylaws of Brek Energy Corporation that were in effect at the time of Brek’s merger into a wholly-owned subsidiary of the Company.
On December 9, 2009, Jeffs also filed an action in Colorado federal district court to obtain a declaration that the 550,000 shares of the Company’s stock being held in escrow under an agreement between the Company and Jeffs belong to, and should be released to, Jeffs pursuant to the terms of the escrow agreement (“Jeffs litigation”).
On or around December 18, counsel for the Company, Bruner, Jeffs, and plaintiffs reached an agreement in principle to settle all claims in both the Sweeney litigation and the Jeffs litigation. This global settlement was documented and finalized in February, 2010.
On February 5, 2010, counsel for the Company, Bruner, Jeffs, and plaintiffs filed an Agreed Motion for Dismissal with Prejudice of the Sweeney litigation. On February 9, 2010, the United States District Court for the Northern District of Illinois, Eastern Division entered a docket entry granting the parties’ Agreed Motion and dismissing the Sweeney litigation with prejudice. On February 16, 2010, counsel for Gasco and Jeffs filed an Agreed Motion for Dismissal with Prejudice of the Jeffs litigation. On February 17, 2010, the United States District Court for the District of Colorado entered an Order of Dismissal with Prejudice. A settlement payment, which was accrued in the accompanying financial statements, was made on February 17, 2010, following this dismissal with prejudice.
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 NYSE Amex under the symbol “GSX.” As of March 3, 2010, the Company had 165 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 foreseeable future. Furthermore, Gasco’s revolving credit facility contains covenants that restrict the payment of dividends. See further discussion in Note 8 - “Credit Facility” of the accompanying financial statements.
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 NYSE Amex 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 our financial position and results of operations as the dates indicated. Certain reclassifications have been made to prior financial data to conform to the current presentation. The balance sheet information below gives effect to the sale of materially all of the assets (the “Asset Sale”) comprising our gathering system and our evaporative facilities, which have been reflected as assets held for sale for all periods presented. See Note 4 “Assets Held for Sale” to the accompanying consolidated financial statements for further discussion. 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
The following discussion should be read in conjunction with our historical consolidated financial statements and notes, as well as the selected historical consolidated financial data included elsewhere in this report.
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 in this report.
Overview
We are a natural gas and petroleum exploitation, development and production company engaged in locating and developing hydrocarbon prospects, primarily in the Rocky Mountain region. Our 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. We are currently focusing our drilling efforts in the Riverbend Project located in the Unita Basin of northeastern Utah, targeting the Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations.
Recent Developments
Sale of Gathering Assets
On February 26, 2010, we completed the sale (the “Closing”) of materially all of the assets (the “Asset Sale”) comprising our gathering system and our evaporative facilities, located in Uintah County, Utah (the “Gathering Assets”), to Monarch Natural Gas, LLC (“Monarch”) pursuant to an Asset Purchase Agreement dated January 29, 2010 (the “Purchase Agreement”). At Closing, we received total cash consideration of $23 million from Monarch, the entirety of which was used to repay amounts outstanding under our Credit Facility (defined below).
Pursuant to the Purchase Agreement, simultaneous with Closing we entered into (i) a transition services agreement with Monarch pursuant to which we will provide certain services relating to the operation of the Gathering Assets to Monarch for a six-month term commencing at Closing; (ii) a gas gathering agreement with Monarch pursuant to which we dedicated our natural gas production from all of our Utah acreage and Monarch will provide gathering, compression and processing services utilizing the Gathering Assets to us; and (iii) a salt water disposal services agreement with Monarch pursuant to which we may deliver salt water produced by our operations to the evaporative facilities that Monarch acquired in the Asset Sale. These agreements will result in less revenue and additional costs with an aggregate annual impact, inclusive of a reduction in depreciation expense, of approximately $3.5 million based on 2009 activity. The Purchase Agreement is subject to customary post-closing terms and conditions for transactions of this size and nature.
Acquisition of Petro-Canada
On February 25, 2010, we completed the acquisition of certain oil and gas leases and lands (the “Petro-Canada Assets”) from Petro-Canada Resources (USA) Inc., a Colorado corporation (“Petro-Canada”), for a purchase price of approximately $482,000, subject to customary post-closing terms and conditions for transactions of this size and nature. The sale was made pursuant to a definitive agreement dated February 4, 2010 by and between us and Petro-Canada. The Petro-Canada Assets include one producing well, one shut-in well with recompletion potential and 5,582 gross and net acres located in Utah west of our Gate Canyon operating area. We funded this acquisition with cash flow from operating activities.
Amendment to Credit Facility
On February 1, 2010, our $250 million revolving credit facility (the “Credit Facility”) was amended to, among other things, incrementally reduce our borrowing base by a fixed amount in connection with certain contemplated asset sales, including the sale of the Gathering Assets described above, and, effective as of April 1, 2010, to automatically reduce to $16 million, regardless of whether any of the contemplated asset sales were consummated. Effective February 26, 2010, in connection with the consummation of the Asset Sale and the application of the proceeds therefrom to pay down outstanding borrowings under our revolving credit facility, we elected to reduce the borrowing base to $16 million effective immediately. Following the $23 million debt repayment, our available credit is approximately $4.0 million.
Resignation of Former Chief Executive Officer; Appointment of Replacement
Effective January 27, 2010, our former Chief Executive Officer and President, Mark Erickson, resigned and was replaced by Charles Crowell as interim Chief Executive Officer and W. King Grant as President.
Impact of Current Credit Markets and Commodity Prices
The severe disruptions in the credit markets and reductions in global economic activity had significant adverse impacts on stock markets and oil and gas-related commodity prices, which contributed to a significant decline in our stock price and negatively impacted our future liquidity. We expect our liquidity will continue to be negatively affected in 2010 by the effects of this activity. The following discussion outlines the potential impacts that reduced commodity prices could have on our business, financial condition and results of operations.
Reduced Cash Flows from Operations Could Impact Our Ability to Fund Capital Expenditures and Meet Working Capital Needs
Oil and gas prices have declined significantly since historic highs in July 2008. To mitigate the impact of lower commodity prices on our cash flows, we entered into commodity derivative instruments for 2009 through the first quarter of 2011 (see Note 5 “Derivatives” to the accompanying consolidated financial statements for further discussion). In the event that commodity prices stay depressed or decline further, our cash flows from operations would be reduced even taking into account our commodity derivative instruments for 2010 and 2011 and may not be sufficient when coupled with available capacity under our Credit Facility to meet our working capital needs or, in the event of a significant decline in commodity prices, fund our 2010 capital expenditure budget. This could cause us to alter our business plans, including further reducing our exploration and development plans.
We are operating under a preliminary capital budget subject to board approval for 2010 of $6 million which will be used primarily for the completion and recompletion projects on our existing wells. Based on current expectations, we intend to fund our budget entirely through cash flow from operations. Consequently, we will monitor spending and cash flow throughout the year and may accelerate or delay investment depending on commodity prices, cash flow expectations and changes in our borrowing capacity.
Effective February 26, 2010, our borrowing base under our Credit Facility was reduced to $16 million from $35 million and as of March 3, 2010, we had $11.5 million of outstanding borrowings thereunder. Our borrowing base could be further reduced in the future by our lenders. Though we anticipate funding our capital budget of $6 million for 2010 through cash flows from operations, an inability to access additional borrowings in excess of our existing $4 million of existing capacity under our Credit Facility will limit our ability to increase our operating budget and execute on our growth plans. The maturity of our Credit Facility and our outstanding $65 million 5.50% Convertible Senior Notes occur in March and October of 2011, respectively. The lenders under our Credit Facility may elect not to extend the maturity of such facility without our having previously refinanced, restructured or repaid the 5.50% Convertible Senior Notes due 2011. Accordingly, an inability to refinance, restructure or repay such convertible notes prior to their maturity on terms acceptable to us may impair our ability to execute on future growth plans. Furthermore, the failure to refinance, restructure or repay such convertible notes or our Credit Facility prior to their maturities may impair our ability to obtain alternate sources of financing. Any refinancing, restructuring or repayment could cause substantial dilution to our stockholders either through the issuance of additional equity or the sale of assets.
If we need additional liquidity for future activities, including paying amounts owed in connection with a borrowing base reduction, if any, we may be required to consider several options for raising additional funds, such as selling securities, selling assets or farm-outs or similar arrangements, but we may be unable to complete any of these transactions on terms acceptable to us or at all. Any financing obtained through the sale of our equity will likely result in substantial dilution to our stockholders.
Reduced Cash Flows from Operations Could Result in a Default under Our Credit Facility and Convertible Senior Notes due 2011
Our Credit Facility contains covenants including those 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 1.0:1.0; and (2) a ratio of senior debt to EBITDAX (as such term is defined in the Credit Facility) for the most recent four quarters not to be greater than 3.5:1.0 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. As of December 31, 2009, our current and senior debt to EBITDAX ratios were 2.9:1.0 and 2.3:1.0, respectively, and we were in compliance with each of the covenants as of December 31, 2009. Sustained or lower oil and natural gas prices and the impact of the sale of our gathering system could reduce our consolidated EBITDAX and thus could reduce our ability to maintain existing levels of senior debt or incur additional indebtedness.
Any failure to be in compliance with any material provision or covenant of our Credit Facility could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under our Credit Facility. Additionally, should our obligation to repay indebtedness under our Credit Facility be accelerated, we would be in default under the indenture governing our Convertible Notes, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such Convertible Notes. To the extent it becomes necessary to address any anticipated covenant compliance issues, we may be required to sell a portion of our assets or issue additional securities, which would be dilutive to our shareholders and may not be on terms acceptable to us.
Reduced Commodity Prices Could Impact the Borrowing Base under Our Credit Facility
Our Credit Facility limits our borrowings to the borrowing base less our total outstanding letters of credit issued there under. As of December 31, 2009, we had loans of approximately $34.5 million outstanding under our Credit Facility and letters of credit in the amount of approximately $455,000 (see Note 8 “Credit Facility” to the accompanying consolidated financial statements for further discussion).
Under the terms of our Credit Facility, our borrowing base is subject to semi-annual redetermination by our lenders thereunder (the “Lenders”) based on their valuation of our proved reserves and their internal criteria. In addition to such semi-annual determinations, our Lenders may request one additional borrowing base redetermination between each semi-annual calculation.
If our borrowing base is further reduced as a result of a redetermination to a level below our then current outstanding borrowings, we will be required to repay the amount by which such outstanding borrowings exceed the borrowing base within 30 days of notification by the Lenders and we will have less or no access to borrowed capital going forward. If we do not have sufficient funds on hand for repayment, we will be required to seek a waiver or amendment from our Lenders, refinance our Credit Facility or sell assets or additional shares of common stock. We may not be able to refinance or complete such transactions on terms acceptable to us, or at all. In the event that we are unable to repay the amount owed within 30 days, we will be in default under the Credit Facility, and as such the Lenders party thereto will have the right to terminate their aggregate commitment under the Credit Facility and declare our outstanding borrowings immediately due and payable in whole. An acceleration of the outstanding indebtedness under the Credit Facility in this manner would additionally constitute an event of default under the indenture governing to our 5.50% Convertible Senior Notes due 2011 (the “Convertible Notes”). Should an event of default occur and continue under the indenture governing the Convertible Notes, the Convertible Notes may be declared immediately due and payable at their principal amount
together with accrued interest and liquidated damages, if any. As such, should we anticipate that we will not be able to repay all amounts owed under the Credit Facility as a result of the anticipated borrowing base redetermination; we will consider, along with previously discussed refinancing and sales, a sale of our company or our assets as well as a voluntary reorganization in bankruptcy. Additionally, if we are unable to repay amounts owed under the Credit Facility, we may be forced into an involuntary reorganization in bankruptcy.
Reduced Commodity Prices May Result in Ceiling Test Write-Downs and Other Impairments
As of March 31, 2009, our full cost pool exceeded the ceiling limitation based on oil and gas prices of $34.40 per barrel and $2.36 per Mcf (see Note 2 “Significant Accounting Policies-Oil & Gas Properties” to the accompanying consolidated financial statements for further discussion). Therefore, impairment expense relating to our ceiling test of $41,000,000 was recorded during the year ended December 31, 2009.
We may be required to further write down the carrying value of our gas and oil properties as a result of low gas and oil prices 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.
Investments in unproved properties are also assessed periodically to ascertain whether impairment has occurred. Our evaluation of impairment of unproved properties incorporates our expectations of developing unproved properties given current and forward-looking economic conditions and commodity prices. As discussed above, we reclassified approximately $1,100,000 and $200,000 of expiring acreage primarily in Utah and California, respectively into proved property. This reclassification represents the value of the leases that will expire during 2010 before we are able to develop them further. We believe that the majority of our remaining unproved costs will become subject to depletion within the next five years, by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before we can explore or develop it further, or by making decisions that further exploration and development activity will not occur.
Reduced Commodity Prices May Impact Our Ability to Produce Economically
Significant or extended price declines may adversely affect the amount of oil and natural gas that we can produce economically. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.
Amendments to Credit Facility
Our Credit Facility 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. Borrowings made under the Credit Facility are secured by a pledge of the capital stock of the Guarantors and mortgages on substantially all of the Company’s oil and gas properties. Interest on borrowings is payable monthly and principal is due at maturity on March 29, 2011.
During May 2009, our Credit Facility was amended to among other things, (i) lower our borrowing base to $35,000,000 from $45,000,000; (ii) increase the interest rate pricing grid; (iii) amend the definition of LIBO Rate to include a floor of 2.00%; (iv) increase the required collateral coverage and the title requirement relating thereto; (v) require us to engage a financial consultant on or prior to May 29, 2009 and (vi) permit us to monetize our commodity hedges (as described in Note 2 of the accompanying financial statements) and use the proceeds to pay down a portion of the approximate $9,000,000 deficiency created by the reduced borrowing base. A special redetermination of our borrowing base on or
around June 30, 2009 was also added, in addition to the scheduled redeterminations and special redeterminations available at our request or the request of the lenders party thereto.
During July 2009, the Credit Facility was amended, among other things, to reschedule the special redetermination of our borrowing base on or about June 30, 2009 to on or about August 31, 2009.
During August 2009, the Credit Facility was further amended, among other things, to increase the interest rate pricing grid by 25 b.p. for Eurodollar based loans and for Alternate Base Rate (“ABR”) priced loans with respect to any periods in which we have utilized at least 90% of the borrowing base. Interest on borrowings under the Credit Facility accrues at variable interest rates at either a Eurodollar rate or an alternate base rate. The Eurodollar rate is calculated as LIBOR plus an applicable margin that varies from 2.50% (for periods in which we have utilized less than 50% of the borrowing base) to 3.50% (for periods in which we have utilized at least 90% of the borrowing base). The alternate base rate is equal to the sum of (i) the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50% and (c) the Adjusted LIBO Rate for a one month interest period on such day plus 1.00% and (ii) an applicable margin that varies from 1.50% (for periods in which we have utilized less than 50% of the borrowing base) to 2.50% (for periods in which we have utilized at least 90% of the borrowing base). We elect the basis of the interest rate at the time of each borrowing under the Credit Facility. However, under certain circumstances, the Lenders may require us to use the non-elected basis in the event that the elected basis does not adequately and fairly reflect the cost of making such loans. This amendment also delayed the special redetermination of our borrowing base previously scheduled to occur on or about August 31, 2009, to on or about September 30, 2009.
During September 2009, the Credit Facility was further amended, among other things, to delay indefinitely the special redetermination of our borrowing base previously scheduled to occur on or about September 30, 2009, as discussed above. On October 30, 2009, the Credit Facility was further amended, among other things, to reschedule the scheduled mid-year redetermination of the borrowing base pursuant to Section 3.02 of the Credit Facility originally scheduled to occur on or about November 1, 2009 to on or about November 30, 2009. Pursuant to the Credit Facility, should there be a borrowing base deficiency after this scheduled mid-year redetermination on or about November 30, 2009, we were permitted 30 days to eliminate such deficiency.
During December 2009, the Credit Facility was amended, among other things, to revise the definition of “Redetermination Date” with respect to scheduled redeterminations for the year ended December 31, 2009 to be on our about May 1 of each year, thereby removing the scheduled redetermination previously scheduled to occur on or about November 30, 2009, and with respect to scheduled redeterminations for the year ended December 31, 2010 to be on our about January 30, May 1 and November 1 of such year. With respect to any scheduled redetermination in subsequent years, however, the Redetermination Date continues to be on or about May 1 and November 1 of each such year. Pursuant to this amendment, should there be a borrowing base deficiency after the scheduled redetermination on or about January 30, 2010. Additionally, the Credit Facility permitted us to terminate the engagement of our financial advisor effective November 29, 2009.
During February 2010, the Credit Facility was amended, among other things, (i) to remove the scheduled redetermination of our borrowing base on or about January 30, 2010 with the effect that scheduled redeterminations for the year ended December 31, 2010 revert to the regular redetermination schedule of every six months on or about May 1 and November 1 of each year and (ii) to reduce our borrowing base to $16 million from $35 million in connection with the sale of our gas gathering system and water disposal facilities and the sale of our interest in certain oil and gas properties (collectively, the “Assets”). Pursuant to the amendment, the borrowing base would be reduced by a fixed amount upon the
consummation of each sale and, effective as of April 1, 2010, would be automatically reduced to $16 million, regardless of whether any of the Assets are sold.
This amendment also increased the interest rate pricing grid by 25 basis points for Eurodollar based loans and for ABR priced loans effective February as of 1, 2010. Interest on borrowings under the Credit Facility accrues at variable interest rates at either a Eurodollar rate or an alternate base rate. The Eurodollar rate is calculated as LIBOR plus an applicable margin that, as amended, varies from 2.75% (for periods in which we have utilized less than 50% of the borrowing base) to 3.75% (for periods in which we have utilized at least 90% of the borrowing base). The alternate base rate, as amended, is equal to the sum of (i) the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50% and (c) the Adjusted LIBO Rate for a one month interest period on such day plus 1.00% and (ii) an applicable margin that varies from 1.75% (for periods in which we have utilized less than 50% of the borrowing base) to 2.75% (for periods in which we have utilized at least 90% of the borrowing base). This amendment further provides that if the borrowing base is greater than $16,000,000 on March 1, 2010, then effective on and after such date the interest rate pricing grid will automatically increase an additional by 25 basis points for Eurodollar based loans and for ABR priced loans. We elect the basis of the interest rate at the time of each borrowing under the Credit Facility. However, under certain circumstances, the Lenders may require us to use the non-elected basis in the event that the elected basis does not adequately and fairly reflect the cost of making such loans. Additionally, this amendment provided for the release of certain liens relating to the Assets that secure our obligations under the Credit Facility.
Effective February 26, 2010, in connection with the consummation of the Asset Sale and the application of the proceeds therefrom to pay down outstanding borrowings, we elected to reduce the borrowing base to $16 million effective immediately. Following the $23 million debt repayment, our available credit is approximately $4.0 million.
Asset Sales & Acquisitions
During June 2009, we sold our drilling rig for proceeds of $1,000,000 which consisted of a cash payment of $500,000 and an interest bearing promissory note of $500,000 with a maturity date of June 30, 2012. We recognized a loss of $905,850 on the sale which is recorded in “Loss on sale of assets, net” in the accompanying consolidated financial statements (see Note 2 “Significant Accounting Policies - Facilities and Equipment” to the accompanying consolidated financial statements for further discussion).
On February 26, 2010, we completed the Asset Sale to Monarch pursuant to the Purchase Agreement. At Closing, we received total cash consideration of $23 million from Monarch, the entirety of which was used to repay amounts outstanding under our Credit Facility.
On February 25, 2010, we completed the acquisition of the “Petro-Canada Assets from Petro-Canada for a purchase price of approximately $482,000, subject to customary post-closing terms and conditions for transactions of this size and nature. The sale was made pursuant to a definitive agreement dated February 4, 2010 by and between us and Petro-Canada. The Petro-Canada Assets include one producing well, one shut-in well with recompletion potential and 5,582 gross and net acres located in Utah west of our Gate Canyon operating area. We funded this acquisition with cash flow from operating activities.
Notice from the NYSE Amex LLC
On June 25, 2009, we received a notice from the NYSE Amex LLC (“NYSE Amex”), dated June 25, 2009, informing us that we did not meet certain of the continued listing standards of the NYSE Amex. Specifically, the notice stated that we were not in compliance with Section 1003(a)(i) of the NYSE Amex Company Guide, with stockholders’ equity of less than $2,000,000 and net losses in two of its three most
recent fiscal years; and Section 1003(a)(ii) of the NYSE Amex Company Guide, with stockholders’ equity of less than $4,000,000 and net losses in three of its four most recent fiscal years. The notice also stated that in order to maintain its listing, we must submit a plan of compliance to the NYSE Amex by July 27, 2009 that addresses how we intend to regain compliance with Sections 1003(a)(i) and 1003(a)(ii) of the NYSE Amex Company Guide by December 27, 2010.
We submitted our plan to the NYSE Amex on July 27, 2009, and provided supplemental information on August 25, 2009, advising the NYSE Amex of the actions we have taken, and plan to take, to attempt to bring the Company into compliance with the applicable listing standards by December 27, 2010.
By letter dated September 15, 2009, the NYSE Amex notified us that it had accepted our plan and determined that, in accordance with Section 1009 of the NYSE Amex Company Guide, we had made a reasonable demonstration of our ability to regain compliance with Section 1003(a)(i) and 1003(a)(ii) of the NYSE Amex Company Guide by December 27, 2010. The NYSE Amex granted us an extension until December 27, 2010 (the “extension period”) to regain compliance with the continued listing standards of the NYSE Amex Company Guide. Our listing on the NYSE Amex is being continued pursuant to this extension through the extension period subject to certain conditions.
We will be subject to periodic review by the NYSE Amex during the extension period. There can be no assurance that we will be able to achieve compliance with Sections 1003(a)(i) and 1003(a)(ii) of the NYSE Amex Company Guide within the required time frame. If we are not able to make progress consistent with our plan or to regain compliance with the continued listing standards by the end of the extension period, we will be subject to delisting procedures as set forth in the NYSE Amex Company Guide.
Drilling Activity
During 2009, we reached total depth on 2 gross wells (approximately 0.84 net wells), one of which was in progress at December 31, 2008, in the Riverbend area. We spudded one new well during 2009 and upon reaching total depth on this well, we released our remaining drilling rig. We did not conduct any initial completion operations. We re-entered three gross operated wells (0.92 net wells) to complete pay zones that were behind pipe. Additionally, we performed limited workover operations on certain Green River Formation oil wells to enhance oil production during the improved oil prices received during the last three quarters of 2009. As of December 31, 2009, we operated 132 gross producing wells. We currently have an inventory of 34 operated wells with up-hole recompletion opportunities and two Upper Mancos wells awaiting initial completion activities.
California Projects
As of December 31, 2009, we had a leasehold interest in approximately 24,996 gross acres (18,492 net acres) in Kern and San Luis Obispo Counties of Southern California. On one of our prospects in Kern County, we entered into a farm-out agreement with a large exploration and production company who has a considerable California operations presence. We received a prospect fee and will be carried for a 20% working interest on the initial well and will turn over operations on the prospect to our partner. The operator has the option to drill a second well in which we will be carried for a 20% working interest.
We currently have entered into agreements and received prospect fees and working interests on three of our California prospects.
In one of our prospects in the San Joaquin Basin of Southern California, exploratory drilling commenced during the fourth quarter of 2009. In mid-December, total depth of 2,400 feet was reached on this non-
operated well in which we have a 33.3% carried working interest. The well encountered oil shows but not in quantities deemed economic to produce and this well was plugged and abandoned. We did not incur any exploration expense or dry well costs on this well. We are currently in discussions with the operator to determine how best to proceed in this area. The operator has approximately 150 days to propose another test well in which we will be carried for a 33.3% working interest.
Summary of Capital Expenditures
The following table summarizes our capital expenditures during 2009 by reconciling the cash paid for acquisitions, development and exploration included within the Consolidated Statement of Cash Flows in Item 8.
Production and Reserve Information
In December 2008, the SEC adopted new rules related to modernizing reserve calculation and disclosure requirements for oil and natural gas companies, which became effective prospectively for annual reporting periods ending on or after December 31, 2009. The new rules expand the definition of oil and gas producing activities to include the extraction of saleable hydrocarbons from oil sands, shale, coal beds or other nonrenewable natural resources that are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. The use of new technologies is now permitted in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Other definitions and terms were revised, including the definition of proved reserves, which was revised to indicate that entities must use the average of beginning-of-the-month commodity prices over the preceding 12-month period, rather than the end-of-period price, when estimating whether reserve quantities are economical to produce. Likewise, the 12-month average price is now used to calculate cost center ceilings for impairment and to compute depreciation, depletion and amortization. Another significant provision of the new rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking.
In January 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-03 “Oil and Gas Reserve Estimation and Disclosure,” which aligns the current oil and gas reserve estimation and disclosure requirements with those of the SEC. As of December 31, 2009, we changed our method of determining the quantities of oil and gas reserves which impacted the amount recorded for depreciation, depletion and amortization and the ceiling test calculation for oil and gas properties. Under the new rules, we prepared our oil and gas reserve estimates as of December 31, 2009 using the average, first-day-of-the- month price during the 12-month period ending December 31, 2009. In prior years, we used the year-end price; therefore, reserve estimates for the year ended December 31, 2009 may not be directly comparable to those presented for prior periods. See Note 3 “Change in Method of Determining Oil and Gas Reserves” of the accompanying financial statements for further discussion. The following table
presents certain of our production information for each of the three years ended December 31, 2009 and our estimated proved reserves as of December 31 of each year presented. The Mcfe calculations assume a conversion of 6 Mcf for each Bbl of oil.
Our oil and gas production decreased by approximately 6% during 2009 as compared with 2008 primarily due to normal production declines partially offset by the completion of new and existing wells during 2009. During 2009 our proved reserve quantities decreased by approximately 13% primarily due to the production during 2009 and the decrease in gas prices used to estimate reserves from $4.63 per mcf at December 31, 2008 to $2.85 per mcf at December 31, 2009. This decrease in reserve quantities was partially offset by an increase in the oil price used to estimate our reserve quantities from $15.33 per barrel at December 31, 2008 to $44.46 per barrel at December 31, 2009.
Oil and gas production increased by approximately 14% during 2008 as compared with 2007 primarily due to the completion of 22 gross (7.3 net) new wells and the recompletion of 13 gross (6.4 net) existing wells during 2008. We elected to shut-in or curtail a portion of our daily production during October and the first part of November 2008 due to lower commodity prices. This curtailment as well as normal production declines partially offset our increased production during 2008. During 2008 our proved reserve quantities decreased by approximately 52% primarily due to the decrease in oil and gas prices used to estimate the reserves from $73.95 per barrel and $6.53 per Mcf at December 31, 2007 to $15.33 per barrel and $4.63 per Mcf at December 31, 2008. Also contributing to the decrease in reserve quantities was the sale of our interest in four gross producing (one net) wells during August 2008.
The revisions of previous estimates during 2009 were due primarily to a decrease in the gas price from $4.63 per mcf at December 31, 2008 to $2.85 per mcf at December 31, 2009 which caused some of our wells to become uneconomic. This decrease was partially offset by an increase in the oil prices from $15.33 per barrel at December 31, 2008 to $44.46 per barrel at December 31, 2009.
The majority of the revisions of previous estimates during 2008 were primarily the result of a decrease in proved undeveloped reserves as the prices of $15.33 per barrel and $4.63 per Mcf that were used to estimate our 2008 reserves caused all of our proved undeveloped reserves to become uneconomic.
The majority of the revisions of previous estimates during 2007 were primarily the result of an increase in proved undeveloped reserves due to the increase in oil and gas prices used to estimate the reserves from $45.53 per barrel and $4.47 per Mcf in 2006 to $73.95 per barrel and $6.53 per Mcf at December 31, 2007.
Reserve Quantities
Liquidity and Capital Resources
The borrowing base under our Credit Facility was reduced to $16,000,000 effective February 26, 2010. Additionally our Credit Facility provides for periodic and special borrowing base redeterminations which could further affect our available borrowing base. Please see “-Impact of Credit Market and Commodity Prices” above for a discussion of our liquidity and the impact of current market conditions thereon.
Sources and Uses of Funds
The following table summarizes our sources and uses of cash for each of the three years ended December 31, 2009, 2008 and 2007.
The decrease in cash provided by operating activities during 2009 as compared with 2008 is primarily due to a 56% decrease in oil and gas revenue resulting from a decrease in oil and gas prices of $3.82 per Mcf and $32.24 per bbl combined with a 6% decrease in production. The increase in cash provided by operating activities from 2007 to 2008 is primarily due to the 86% increase in oil and gas revenue resulting from a 14% increase in production as well as an increase in oil and gas prices of $2.86 per Mcf and $21.33 per bbl during 2008.
Our investing activities during the three years ended December 31, 2009 related primarily to our development and exploration activities. In 2009 we had sales proceeds of $539,450 related to the sale of our drilling rig and certain other field equipment, in 2008 we had sales proceeds of $7,500,000 which represented the sale of a non-operated interest in four producing wells and in 2007 we had sales proceeds of $3,475,153 which represented the sale of a partial interest in two of our producing wells. We sold $6,000,000 of our short-term investments during 2007. The remaining investing activity during 2007 consisted of changes in our restricted investments.
During 2009, 2008 and 2007, our financing activity consisted primarily of borrowings and repayments under our Credit Facility. The activity in 2008 included $1,161,057 in proceeds from the exercise of options to purchase common stock. The 2007 activity included a public offering of 10,000,000 shares of our common stock for gross proceeds of approximately $19,300,000.
Monetization of Derivative Contracts
During May 2009, we monetized selected natural gas hedge contracts for net proceeds of $8,528,731. These proceeds were used to repay a portion of our outstanding borrowings under our Credit Facility as further described in Note 8 “Credit Facility” in the accompanying consolidated financial statements. Concurrent with the monetization of the hedges, we re-hedged a portion of our production for the period June 2009 through March 2011. The new derivative contracts were entered into at a weighted average price over the contract periods. We elected the weighted average price scenario for a portion of our natural gas volumes in an effort to secure the best prices for the 2009 contract period. See Note 5 “Derivatives” to the accompanying consolidated financial statements for further discussion.
Sales of Assets
During June 2009, we sold our drilling rig for proceeds of $1,000,000 which consisted of a cash payment of $500,000 and an interest bearing promissory note of $500,000 with a maturity date of June 30, 2012. We recognized a loss of $905,850 on the sale which is recorded in “Loss on sale of assets, net” in the accompanying consolidated financial statements (see Note 2 “Significant Accounting Policies - Facilities and Equipment” to the accompanying consolidated financial statements for further discussion).
In February 2010, we completed the Asset Sale to Monarch pursuant to the Purchase Agreement. At Closing, we received total cash consideration of $23 million from Monarch, the entirety of which was used to repay the amounts outstanding under our credit facility.
Schedule of Contractual Obligations
The following table summarizes the Company’s obligations and commitments to make future payments under its notes payable, operating leases, employment contracts, consulting agreements and service contracts for the periods specified as of December 31, 2009.
Forward Sales Contracts
During April 2009, we entered into a firm sales and transportation agreement to sell up to 50,000 MMBtu per day of our 2010 and 2011 gross production from the Uinta Basin. The contract contains two pricing mechanisms: (1) up to 25,000 MMBtu per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price.
We believe that we are not required to treat the contracts as derivatives and the contracts will not be marked to market because we anticipate that (1) we will produce the volumes required to be delivered under the terms of the contracts, (2) it is probable the delivery will be made to the applicable counterparty and (3) the applicable counterparty will fulfill its contractual obligations under the terms of the contracts.
Capital Budget
Based on current expectations, we intend to fund our 2010 capital expenditure program entirely through cash flow from operations. This program will focus primarily on completion and recompletion projects on our existing wells. Consequently, we will monitor spending and cash flow throughout the year and may accelerate or delay investment depending on commodity prices, cash flow expectations and changes in our borrowing capacity.
Credit Facility
The Credit Facility 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. Borrowings made under the Credit Facility are secured by a pledge of the capital stock of the Guarantors and mortgages on substantially all of the Company’s oil and gas properties. Interest on borrowings is payable monthly and principal is due at maturity on March 29, 2011.
On February 1, 2010, we amended our Credit Facility to, among other things, (i) remove the scheduled redetermination of our borrowing base on or about January 30, 2010 with the effect that scheduled redeterminations for the year ended December 31, 2010 revert to the regular redetermination schedule of every six months on or about May 1 and November 1 of each year and (ii) reduce our borrowing base to $16 million from $35 million in connection with the contemplated sale of our gathering assets and the sale of our interest in certain oil and gas properties. The amendment provided that the borrowing base would be incrementally reduced by a fixed amount upon the consummation of each sale and, effective as of April 1, 2010, would be automatically reduced to $16 million, regardless of whether any of the contemplated asset sales were consummated. Effective February 26, 2010, in connection with the consummation of the sale of our gathering assets and the application of the proceeds therefrom to pay down outstanding borrowings, we elected to reduce the borrowing base to $16 million effective immediately. Following the $23 million debt repayment, our available credit is approximately $4.0 million. For further discussion of each amendment, see “Amendments to Credit Facility” in “Item 7 -Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The Credit Facility 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 1.0:1.0; and (2) a ratio of Senior Debt to EBITDAX (as such terms are defined in the Credit Facility) for the most recent four quarters not to be greater than 3.5:1.0 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. Sustained or lower oil and natural gas prices could reduce our consolidated EBITDAX and thus could reduce our ability to maintain existing levels of Senior Debt or incur additional indebtedness. Any failure to be in compliance with any material provision or covenant of the Credit Facility could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under the Credit Facility. Additionally, should our obligation to repay indebtedness under the Credit Facility be accelerated, we would be in default under the indenture governing the Convertible Notes, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such convertible notes. To the extent it becomes necessary to address any anticipated covenant compliance issues, we will seek to obtain a waiver or amendment of the Credit Facility from the Lenders, and in the event that such waiver or amendment is not granted, we may be required to sell a portion of our assets or issue additional securities, which would be dilutive to our shareholders. Any sale of assets or issuance of additional securities may not be on terms acceptable to us.
As of December 31, 2009, there were loans of $34,544,969 outstanding and letters of credit in the amount of $455,029 under the Credit Facility, which are considered usage for purposes of calculating availability and commitment fees.
As of December 31, 2009, our current and senior debt to EBITDAX ratios were 2.9:1.0 and 2.3:1.0, respectively, and we were in compliance with each of the covenants contained in the Credit Facility.
Convertible Notes
On October 20, 2004 (the “Issue Date”), we closed the private placement of $65,000,000 in aggregate principal amount of 5.50% Convertible Senior Notes due 2011 (the “Convertible Notes”) pursuant to an Indenture dated as of October 20, 2004 (the “Indenture”), between us 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 our 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.
We may, at our option, 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 us to repurchase all of that holder’s notes 45 days after we give 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 and rank on parity (except as described above) in right of payment with all of our existing and future unsecured and unsubordinated indebtedness. The Convertible Notes effectively rank junior to any future secured indebtedness and junior to our subsidiaries’ liabilities. The Indenture does not contain any financial covenants or any restrictions on the payment of dividends, the repurchase of our 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 our 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 was $40,218,750 as of December 31, 2009, based on market quotes.
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, 2009, natural gas derivative instruments were comprised of two swap agreements for 2010 through March 2011 production. The fair value of the agreements was a current liability of $1,932,513 and a noncurrent liability of $761,092 as of December 31, 2009. The fair value of the agreements was a current asset of $8,855,947 as of December 31, 2008. These instruments allow us to predict with greater certainty the effective natural gas prices to be received for our economically 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 our exposure to adverse market changes, we have entered into various derivative instruments. As of December 31, 2009, our derivative instruments consisted of two swap agreements for our 2010 through March 2011 production. The fair market values of these agreements were a current liability of $1,932,513 and a noncurrent liability of $761,092 as of December 31, 2009. 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, we receive 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 swap agreements for 2010 through March 2011 are summarized in the table below:
(a)
Northwest Pipeline Rocky Mountains - Inside FERC first of month index price.
(b)
Includes information pertaining to a portion of a single natural gas derivative contract with declining volumes. The fixed price represents the weighted average price for the entire period from June 2009 through March 2011.
The swap contracts 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. Our hedging contracts have no requirements for us to post additional collateral based upon the changes in the market value of our hedge instruments.
Interest Rate Risk
We do not currently use interest rate derivatives to mitigate our exposure, including under our revolving credit facility, to the volatility in interest rates.
ITEM 8
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Gasco Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Gasco Energy, Inc. and subsidiaries (the Company) as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 financial position of Gasco Energy, Inc. and subsidiaries as of December 31, 2009 and 2008, and the results of its operations and its cash flows for the years then ended 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, 2009, 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 March 3, 2010 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Denver, Colorado
March 3, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Gasco Energy, Inc.
We have audited the consolidated balance sheet of Gasco Energy, Inc. and subsidiaries as of December 31, 2007 (not separately included herein), and the related consolidated statements of income, retained earnings and cash flows for the year then ended. 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 audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Gasco Energy, Inc. and subsidiaries as of December 31, 2007, and the results of their operations and their cash flows for each of the year ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.
/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 (DEFICIT)
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, 2009, 2008 AND 2007
NOTE 1 - ORGANIZATION AND LIQUIDITY
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 Green River, Wasatch, Mesaverde, Blackhawk, Mancos, Dakota and Morrison formations.
The Company has evaluated subsequent events through March 3, 2010, the filing date of this Annual Report on Form 10-K for the year ended December 31, 2009, and has disclosed such items in Note 8 “Credit Facility,” Note 15 “Commitments,” Note 18 “Legal Proceedings” and Note 21 “Subsequent Events” herein.
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.
Concentration of Credit Risk
The Company’s cash equivalents 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, 2009 and 2008, 84% and 68%, respectively, of the Company’s production was sold to Anadarko Petroleum Corporation, during 2009 12% of the Company’s production was sold to EnWest Marketing LLC and during 2008 and 2007, 21% and 80%, respectively was sold to
ConocoPhillips Company. Approximately 46% of the accounts receivable - revenue as of December 31, 2009 are due from Anadarko Petroleum Corporation. However, Gasco does not believe that the loss of a single purchaser, including Anadarko Petroleum Corporation, 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, internal costs directly related to exploration and development activities and costs of drilling both productive and non-productive wells. The Company capitalized $47,617, $329,627 and $129,825 of internal costs during the years ended December 31, 2009, 2008 and 2007, respectively. Additionally we capitalized stock compensation expense related to our drilling consultants as further described in Note 6 “Stock-Based Compensation” herein. 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 of $38,638,936 as of December 31, 2009, 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 2009, we reclassified approximately $1,100,000 and $200,000 of expiring acreage primarily in Utah and California, respectively into proved property. This acreage represents the leases that will expire during 2010 before we are able to develop it further. During 2008, we reclassified approximately $1,250,000 and $750,000 of expiring acreage primarily in Utah and California, respectively into proved property. These costs were included in the ceiling test and depletion calculations during the quarter in which the reclassifications were made.
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. Estimated reserve quantities are affected by changes in commodity prices and actual well performance.
Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion (full cost pool) 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 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, net of income taxes (ceiling limitation). Should the full cost pool exceed this ceiling limitation, an impairment is recognized. The present value of estimated future net revenues is computed by applying current oil and gas prices for quarters prior to December 31, 2009 and the average, first-day-of-the- month price during the 12-month period ended December 31, 2009 for the quarter ended December 31, 2009 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. Prior to December 31, 2009, subsequent commodity price increases could be utilized to calculate the ceiling value. See Note 3 “Change in Method of Determining Oil and Gas Reserves” for discussion of changes in the ceiling test as of December 31, 2009.
As of March 31, 2009, the Company’s full cost pool exceeded the ceiling limitation, based on oil and gas prices of $34.40 per barrel and $2.36 per Mcf, by $41,000,000. There was no additional ceiling test impairment expense recorded for the remaining nine months of 2009. Therefore, impairment expense related to our oil and gas properties of $41,000,000 was recorded during the twelve months ended December 31, 2009. No impairment expense related to our oil and gas properties was recorded during 2008.
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.
Wells in progress at December 31, 2008 represented 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, 2008, it was classified as wells in progress and was withheld from the depletion calculation and the ceiling test. The costs for this well were transferred into proved property during the first quarter of 2009 when the well reached total depth and was cased and became subject to depletion and the ceiling test calculation in future periods.
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 were $548,047. No interest was capitalized during 2009 or 2008.
Facilities and Equipment
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 were 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, the net income or (expense) attributable to the outside working interest owners from the evaporation pits of $(49,449), $260,846, and $179,766 was recorded as an adjustment to proved properties during 2009, 2008 and 2007, respectively. These assets were reclassified as assets held for sale during the fourth quarter of 2009 as described below.
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 for the equipment, twenty five years for the drilling rig which was sold in June 2009 as described below. The rental of the equipment owned by Gasco is charged to the wells that are operated by Gasco and therefore, net income or (expense) attributable to the outside working interest owners from the equipment rental of $(52,444), $688,174 and $887,080 was recorded as an adjustment to proved properties during 2009, 2008 and 2007, respectively.
Through the beginning of June 2009, the Company owned a drilling rig that it leased to an operator for the drilling of wells that it did not operate. During June 2009 the Company sold the drilling rig for proceeds of $1,000,000 which consisted of a cash payment of $500,000 and an interest bearing promissory note of $500,000 with a maturity date of June 30, 2012. The Company recognized a loss of $905,850 on the sale, which is included in “Loss on sale of assets, net” in the accompanying consolidated financial statements.
Assets Held for Sale
During the fourth quarter of 2009, the Company adopted a plan to dispose of and was actively engaged in marketing for sale its gathering assets and water disposal facilities. In February 2010, the Company entered into an asset purchase agreement to sell these assets for total cash consideration of $23,000,000 subject to certain adjustments. These assets have been separately presented in the balance sheets as of December 31, 2009 and 2008 at the lower of carrying value or fair value less the cost to sell and at carrying value, respectively. Additionally, the asset retirement obligations related to these assets have also been reclassified to liabilities associated with assets held for sale as of December 31, 2009 and 2008. See Note 4 “Assets Held for Sale” for further discussion.
Impairment of Long-lived Assets
The Company’s unproved properties are evaluated quarterly for the possibility of potential impairment and are reduced to fair value if the sum of expected undiscounted future cash flows is less than net book value.
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, the debt issuance costs incurred in connection with the Company’s credit facility and the additional debt issuance costs associated with the amendment of our credit facility during 2008 (see Note 8). The Company recorded amortization expense of $608,621, $521,428 and $518,233 related to these costs during the years ended December 31, 2009, 2008 and 2007, respectively.
Forward Sales Contracts
During April 2009, the Company entered into a firm sales and transportation agreement to sell up to 50,000 MMBtu per day of its 2010 and 2011 gross production from the Uinta Basin. The contract contains two pricing mechanisms: (1) up to 25,000 MMBtu per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price.
The Company believes that it is not required to treat the contracts as derivatives and the contracts will not be marked to market because the Company anticipates that (1) it will produce the volumes required to be delivered under the terms of the contracts, (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.
Derivatives
The Company uses derivative instruments to provide a measure of stability to its cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. The Company records all derivative instruments at fair value within the accompanying consolidated balance sheets. Changes in fair value are to be recognized currently in earnings unless specific hedge accounting criteria are met. Management has decided not to use hedge accounting under the accounting guidance for its derivatives and therefore, the changes in fair value are recognized in earnings. On January 1, 2009, the Company adopted authoritative guidance related to derivatives and hedging, and has included the required enhanced quantitative and qualitative disclosure about objectives and strategies for using derivatives, quantitative disclosures about fair value and amounts of gains and losses from derivative instruments, and disclosures about counterparty credit risk and collateral requirements.
Asset Retirement Obligation
The Company accounts for its future asset retirement obligations by recording the fair value of the liability during the period in which it was incurred. 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, gathering assets or evaporative facility costs (see earlier discussion of assets held for sale) in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs and gathering assets using the units-of-production method and the evaporative facilities are depreciated on a straight-line basis over the life of the assets. The Company’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.
Contract Termination Fee
During February 2009, the Company released its remaining leased drilling rig and paid the rig contractor $4,701,000 for early termination of the drilling contract, as calculated at $12,000 per day from the rig release date through March 15, 2010, the expiration date of the contract. Upon the Company’s payment of
this fee, the letter of credit in the amount of $6,564,000 for the benefit of the rig contractor was released by the Company’s lenders.
Off Balance Sheet Arrangements
From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2009, 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, 2009 and 2008 were not significant.
Computation of Net Loss per Share
Basic net income (loss) per share is computed by dividing net income (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 and employees of the Company are included in the computation of basic net income (loss) per share only after the shares become fully vested. Diluted net income per common share includes both the vested and unvested shares of restricted stock and the potential dilution that could occur upon exercise of the options to acquire common stock computed using the treasury stock method which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of the options (which were assumed to have been made at the average market price of the common shares during the reporting period).
The table below sets forth the computations of basic and diluted net income per share for the year ended December 31, 2008. Basic and diluted net loss per share were the same in each of the years ended December 31, 2009 and 2007.
The 16,250,000 shares of common stock that would have been issued upon conversion of the Convertible Notes have been excluded from the diluted weighted average shares outstanding during the year ended December 31, 2008 because the inclusion of such shares would have been antidilutive. For the year ended December 31, 2008, 4,602,937 options to purchase common stock, respectively, were not included in the diluted weighted average shares outstanding because the exercise of these options would have been anti-dilutive. During the years ended December 31, 2009 and 2007 potential common stock of equivalents of 28,346,672 and 26,979,138, respectively, were excluded from the computation of net income (loss) per share.
Use of Estimates
The preparation of the financial statements for the Company in conformity with generally accepted accounting principles in the United States (“US GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported 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 and to proved oil and gas properties.
Other Comprehensive Income (Loss)
The Company does not have any items of other comprehensive income (loss) for the years ended December 31, 2009, 2008 and 2007. 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’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 2006 and for state and local tax authorities for years before 2005.
Stock Compensation
The Company recognizes compensation cost for stock-based awards based on estimated fair value of the award and records compensation expense over the requisite service period. See Note 6 “Stock-Based Compensation” herein, for further discussion.
Recently Issued Accounting Pronouncements
In June 2009, the Financial Accounting Standards Board (“FASB”) issued “FASB Accounting Standards Codification™ (“Codification”), as the single source of authoritative US GAAP” for all non-governmental entities, with the exception of the SEC and its staff. The Codification, which became effective July 1, 2009, changes the referencing and organization of accounting guidance and was effective for interim and annual periods ending after September 15, 2009. The Company adopted the Codification on July 1, 2009 which provides for changes in references to technical accounting literature (if used) in this Annual Report on Form 10-K and subsequent reports, but did not have a material impact on the Company’s financial position, results of operations or cash flows.
In June 2009, the FASB issued new accounting guidance related to the accounting and disclosures of subsequent events. This guidance incorporates the subsequent events guidance contained in the auditing standards literature into authoritative accounting literature. It also requires entities to disclose the date through which they have evaluated subsequent events and whether the date corresponds with the release of their financial statements. This guidance was effective for all interim and annual periods ending after June 15, 2009. The Company adopted this guidance upon its issuance and it had no material impact on the Company’s consolidated financial statements. The Company evaluates subsequent events up to immediately prior to the issuance of its consolidated financial statements, and for purposes of the accompanying consolidated financial statements, the Company has evaluated subsequent events through March 3, 2010, the filing date of this 10-K, and has disclosed such items in Note 8 “Credit Facility” herein.
In August 2009, the FASB issued new accounting guidance to provide clarification on measuring liabilities at fair value when a quoted price in an active market is not available. This guidance became effective for us on October 1, 2009. The Company adopted this guidance on October 1, 2009, and it had no material impact on the consolidated financial statements.
Please refer to the earlier disclosure for Derivatives, Note 3 “Change in Method of Determining Oil and Gas Reserves” and Note 10 “Fair Value Measurements” for additional information on the recent adoption of new authoritative accounting guidance.
NOTE 3 - CHANGE IN METHOD OF DETERMINING OIL AND GAS RESERVES
In December 2008, the SEC adopted new rules related to modernizing reserve calculation and disclosure requirements for oil and natural gas companies, which became effective prospectively for annual reporting periods ending on or after December 31, 2009. The new rules expand the definition of oil and gas producing activities to include the extraction of saleable hydrocarbons from oil sands, shale, coal beds or other nonrenewable natural resources that are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction. The use of new technologies is now permitted in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Other definitions and terms were revised, including the definition of proved reserves, which was revised to indicate that entities must use the average of beginning-of-the-month commodity prices over the preceding 12-month period, rather than the end-of-period price, when estimating whether reserve quantities are economical to produce. Likewise, the 12-month average price is now used to calculate cost center ceilings for impairment and to compute depreciation, depletion and amortization. Another significant provision of the new rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. The revised rules became effective for the Company’s Annual Report on Form 10-K for the fiscal year ending December 31, 2009. The SEC precluded application of the new rules in quarterly reports prior to the first annual report in which the revised disclosures are required and early adoption is not permitted.
In January 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-03 “Oil and Gas Reserve Estimation and Disclosure,” which aligns the current oil and gas reserve estimation and disclosure requirements with those of the SEC. As of December 31, 2009, the Company changed its method of determining the quantities of oil and gas reserves which impacted the amount recorded for depreciation, depletion and amortization and the ceiling test calculation for oil and gas properties. Under the new rules, the Company prepared its oil and gas reserve estimates as of December 31, 2009 using the average, first-day-of-the- month price during the 12-month period ending December 31, 2009. In prior years through September 30, 2009, the Company used the year-end price. The Company calculates depreciation, depletion and amortization on a quarterly basis using estimated reserves as of the end of each quarter. As a result, the new rules impacted the amount of depreciation, depletion and amortization recorded for oil and gas properties and the ceiling test calculation for the quarter ended December 31, 2009. In addition, under the new guidance, subsequent price increases cannot be considered in the ceiling test calculation.
The adoption of the new rules is considered a change in accounting principle inseparable from a change in accounting estimate. The Company does not believe that provisions of the new guidance, other than pricing, significantly impacted the reserve estimates or consolidated financial statements. The Company does not believe that it is practicable to estimate the effect of applying the new rules on net loss or the amount recorded for depreciation, depletion and amortization for the year ended December 31, 2009.
NOTE 4 - ASSETS HELD FOR SALE
During the fourth quarter of 2009, the Company adopted a plan to dispose of and was actively engaged in marketing for sale its gathering assets and water disposal facilities. In February 2010, the Company entered into an asset purchase agreement to sell these assets for total cash consideration of $23,000,000 subject to certain adjustments. These assets have been separately presented in the consolidated balance sheets as of December 31, 2009 and 2008 at the lower of carrying value or fair value less the cost to sell. Additionally, the asset retirement obligations related to these assets have also been reclassified to liabilities associated with assets held for sale. The Company determined that the revenue and expenses
from these assets do not qualify for discontinued operations accounting. The following table summarizes the assets and liabilities related to the assets held for sale as of December 31, 2009 and 2008.
NOTE 5 - DERIVATIVES
As of December 31, 2009, natural gas derivative instruments consisted of two swap agreements for 2009 through March 2011 gas production. As of December 31, 2008, natural gas derivative instruments consisted of two swap agreements and a costless collar for the calendar year of 2009 gas production. The following table details the fair value of the derivatives recorded in the consolidated balance sheets, by category:
These instruments allow the Company to predict with greater certainty the effective natural gas prices to be realized for its production. The Company’s derivative contracts are described below:
•
For its swap instruments, the Company 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.
•
The Company’s costless collar contained a fixed floor price (put) and ceiling price (call). If the market price exceeded the call strike price or fell below the put strike price, Gasco received the fixed price and paid the market price. If the market price was between the call and the put strike prices, no payments were due from either party.
During May 2009, the Company monetized selected natural gas hedge contracts for net proceeds of $8,528,731. These proceeds were used to repay a portion of the Company’s outstanding borrowings as further described in Note 8 “Credit Facility” herein. Concurrent with the monetization of the hedges, the Company re-hedged a portion of its production for the period June 2009 through March 2011 as further detailed below. The new derivative contracts were entered into at a weighted average price over the contract periods. The Company elected the weighted average price scenario for a portion of its natural gas volumes in an effort to secure what it believes to be the best prices for the 2009 contract period.
The table below summarizes the realized and unrealized gains and losses related to the Company’s derivative instruments for the years ended December 31, 2009, 2008 and 2007.
These realized and unrealized gains and losses are recorded in the accompanying consolidated statements of operations as derivative gains (losses).
The Company’s swap agreements for 2010 through March 2011 are summarized in the table below:
(a)
Northwest Pipeline Rocky Mountains - Inside FERC first of month index price.
(b)
Includes information pertaining to a portion of a single natural gas derivative contract with declining volumes. The fixed price represents the weighted average price for the entire period from June 2009 through March 2011.
NOTE 6 - STOCK-BASED COMPENSATION
The Company accounts for its stock-based compensation by measuring this cost at the grant date based on the fair value of the award and recognizing it 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 includes 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, 2009, 2008 and 2007. 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 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 $18,042, $86,363 and $56,370 during the years ended December 31, 2009, 2008 and 2007, respectively. Of these amounts, $7,110, $31,026 and
$46,285 of compensation expense relating to drilling consultants was capitalized during the years ended December 31, 2009, 2008 and 2007, respectively.
As of December 31, 2009, options to purchase an aggregate of 12,096,672 shares of the Company’s common stock and 140,500 shares of restricted stock were outstanding. These awards were granted during the years from 2001 through 2009 to the Company’s employees, directors and consultants. The options have exercise prices ranging from $0.22 to $5.69 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 $1,933,843, $3,047,661 and $3,075,037 before taxes for the years ending December 31, 2009, 2008, and 2007, respectively.
During the years ended December 31, 2009, 2008 and 2007, 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 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 2009, 2008, and 2007 was calculated using the following assumptions:
The weighted average grant-date fair value of options granted to employees and directors during 2009, 2008, and 2007 was $0.31, $1.02, and $1.38, 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.
Stock Options
The following table summarizes the stock option activity in the equity incentive plans during the years ended December 31, 2009, 2008 and 2007:
The following table summarizes information related to the outstanding and vested options as of December 31, 2009:
The aggregate intrinsic value in the table above is based on the Company’s closing common stock price of $0.53 as of December 31, 2009, 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, 2008 was $983,238. There were no options exercised during the years ending December 31, 2009 and 2007.
The Company settles employee stock option exercises with newly issued common shares.
As of December 31, 2009, there was $1,711,190 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 period of 2.74 years.
During the year ended December 31, 2009, the Company granted options to purchase 1,752,083 shares of common stock with exercise prices ranging from $0.22 to $5.69 per share. The weighted average grant-date fair value of the options granted during the twelve months ended December 31, 2009 was $0.31 per share.
During the year ended December 31, 2008, the Company cancelled 1,255,000 stock options with exercise prices ranging from $3.10 to $5.69. In exchange, the Company granted to the optionees 316,250 stock options with an exercise price of $1.00. This resulted in a modification of the original award. However, because the fair value of the issued options did not exceed the fair value of the cancelled options on the date of the exchange, no incremental compensation expense was recognized.
The following table summarizes the stock options outstanding at December 31, 2009.
Restricted Stock
The following table summarizes the restricted stock activity for the years ending December 31, 2009, 2008 and 2007:
The total grant date fair value of the shares vested during the years ending December 31, 2009, 2008, and 2007 was $159,051, $166,400 and $533,362, respectively.
As of December 31, 2009, there was $213,927 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 2.74 years.
NOTE 7 - OIL AND GAS PROPERTY
The Company’s oil and gas properties are 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:
During the third quarter of 2008, Gasco sold its interest in four gross producing wells (one net producing well), leasehold interests and proven reserves in the Prickly Pear Field in the West Tavaputs area in the Uinta Basin to the operator of these wells. The effective date of the sale was August 21, 2008 and the sales proceeds of $7,500,000 were credited to the full cost pool.
At December 31, 2009 the Company’s unproved properties consist of leasehold acquisition and exploration costs in the following areas:
During the years ended December 31, 2009 and 2008, we reclassified approximately $1,100,000 and $200,000 and $1,250,000 and $750,000 of expiring acreage primarily in Utah and California, respectively, into proved property and included these amounts in the ceiling test and depletion calculations. This acreage represents the leases that will expire before we are able to develop them further.
The following table sets forth a summary of oil and gas property costs not being amortized as of December 31, 2009, by the year in which such costs were incurred.
We believe that the majority of our unproved costs will become subject to depletion within the next five years, by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before we can explore or develop it further, or by making decisions that further exploration and development activity will not occur.
NOTE 8 - CREDIT FACILITY
The Credit Facility 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. Borrowings made under the Credit Facility are secured by a pledge of the capital stock of the Guarantors and mortgages on substantially all of the Company’s oil and gas properties. Interest on borrowings is payable monthly and principal is due at maturity on March 29, 2011.
The Credit Facility requires the Company to comply with financial covenants that require it 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 1.0:1.0; and (2) a ratio of Senior Debt to EBITDAX (as such terms are defined in the Credit Facility) for the most recent four quarters not to be greater than 3.5:1.0 for each fiscal quarter. In addition, the Credit Facility contains covenants that restrict the Company’s ability to incur other indebtedness, create liens or sell the Company’s assets, pay dividends on the Company’s common stock and make certain investments. Sustained or lower oil and natural gas prices could reduce the Company’s consolidated EBITDAX and thus could reduce the Company’s ability to maintain existing levels of Senior Debt or incur additional indebtedness. Any failure to be in compliance with any material provision or covenant of the Credit Facility could result in a default which would, absent a waiver or amendment, require immediate repayment of outstanding indebtedness under the Credit Facility. Additionally, should the Company’s obligation to repay indebtedness under the Credit Facility be accelerated, the Company would be in default under the indenture governing the Convertible Notes, which would require repayment of the outstanding principal, interest and liquidated damages, if any, on such convertible notes. To the extent it becomes necessary to address any anticipated covenant compliance issues, the Company will seek to obtain a waiver or amendment of the Credit Facility from the Lenders, and in the event that such waiver or amendment is not granted, the Company may be required to sell a portion of its assets or issue additional securities, which would be dilutive to the Company’s shareholders. Any sale of assets or issuance of additional securities may not be on terms acceptable to the Company.
As of December 31, 2009, there were loans of $34,544,969 outstanding and letters of credit in the amount of $455,029 under the Credit Facility, which are considered usage for purposes of calculating availability and commitment fees. Effective February 26, 2010, in connection with the consummation of the sale of our gathering assets and the application of the aggregate proceeds therefrom of $23 million to pay down outstanding borrowings, we elected to reduce the borrowing base to $16 million effective immediately. Following the $23 million debt repayment, our available credit is approximately $4.0 million.
As of December 31, 2009, the Company’s current and senior debt to EBITDAX ratios were 2.9:1.0 and 2.3:1.0, respectively, and the Company was in compliance with each of the covenants contained in the Credit Facility.
During 2009 and into 2010, we amended our Credit Facility several times, and the terms of such amendments are summarized below.
Summary of Amendments to the Credit Facility During 2009
On May 14, 2009, the Company and the other parties to the Credit Facility entered into the Third Amendment to the Credit Facility (the “Third Amendment”). Pursuant to the Third Amendment, the Credit Facility was amended to, among other things: (i) increase the interest rate pricing grid; (ii) amend the definition of LIBO Rate to include a floor of 2.00%; (iii) increase the required collateral coverage and the title requirement relating thereto; (iv) require the Company to engage a financial consultant on or prior to May 29, 2009 and (v) permit the Company to monetize its commodity hedges and use the proceeds to pay down outstanding borrowings under the Credit Facility.
Furthermore, the Third Amendment involved a redetermination of the Company’s borrowing base, which was lowered to $35,000,000 from $45,000,000. Because the amount borrowed exceeded the revised borrowing base by approximately $9,000,000, the Company was required to prepay the Credit Facility by an amount equal to the deficiency. On May 7, 2009, the Company monetized selected oil and natural gas hedge contracts and the net proceeds of $8,528,731 were used to repay a portion of the deficiency and the remainder was repaid with cash on hand.
As stated, the Third Amendment revised the definition of LIBO Rate to include a floor of 2.00%. The Minimum Collateral Amount required under the Credit Facility was set at 55% of the Engineered Value of Borrowing Base Properties for the 10-day period commencing on the Effective Date and is required to increase to 90% of the Engineered Value of Borrowing Base Properties thereafter. The related title requirement was also increased to require evidence of title to 80% of the applicable Minimum Collateral Amount percentage of the Engineered Value of Borrowing Base Properties.
Finally, the Third Amendment required the Company to retain a financial consultant acceptable to the Administrative Agent by May 29, 2009, for and until such time as the Administrative Agent consents to termination. Accordingly, effective May 29, 2009, the Company executed an engagement letter with an entity who acted as the Company’s financial consultant and advisor with the approval of the Administrative Agent.
On July 6, 2009, the Company and the other parties to the Credit Facility entered into the Fourth Amendment to Credit Facility (the “Fourth Amendment”), pursuant to which the Credit Facility was amended, among other things, to delay the special redetermination of the Company’s borrowing base previously scheduled to occur on or about June 30, 2009, to on or about August 31, 2009.
On August 28, 2009, the Company and the other parties to the Credit Facility entered into the Fifth Amendment to Credit Facility (the “Fifth Amendment”), pursuant to which the Credit Facility was amended, among other things, to increase the interest rate pricing grid by 25 b.p. for Eurodollar based loans and for ABR priced loans with respect to any periods in which the Company has utilized at least 90% of the borrowing base. Interest on borrowings under the Credit Facility accrues at variable interest rates at either a Eurodollar rate or an alternate base rate. The Eurodollar rate is calculated as LIBOR plus an applicable margin that varies from 2.50% (for periods in which the Company has utilized less than 50% of the borrowing base) to 3.50% (for periods in which the Company has utilized at least 90% of the borrowing base). The ABR is equal to the sum of (i) the greater of (a) the Prime Rate, (b) the Federal
Funds Effective Rate plus 0.50% and (c) the Adjusted LIBO Rate for a one month interest period on such day plus 1.00% and (ii) an applicable margin that varies from 1.50% (for periods in which the Company has utilized less than 50% of the borrowing base) to 2.50% (for periods in which the Company has utilized at least 90% of the borrowing base). The Company elects the basis of the interest rate at the time of each borrowing under the Credit Facility. However, under certain circumstances, the Lenders may require the Company to use the non-elected basis in the event that the elected basis does not adequately and fairly reflect the cost of making such loans. The Fifth Amendment also delayed the special redetermination of the Company’s borrowing base previously scheduled to occur on or about August 31, 2009, to on or about September 30, 2009.
On September 30, 2009, the Company and the other parties to the Credit Facility entered into the Sixth Amendment to Credit Facility (the “Sixth Amendment”), pursuant to which the Credit Facility was amended, among other things, to delay indefinitely the special redetermination of the Company’s borrowing base previously scheduled to occur on or about September 30, 2009.
On October 30, 2009, the Company and the other parties to the Credit Facility entered into the Seventh Amendment to Credit Facility (the “Seventh Amendment”), pursuant to which the Credit Facility was amended, among other things, to revise the definition of “Redetermination Date” with respect to scheduled redeterminations for the year ended December 31, 2009 to be on or about May 1 and November 30 of such year, thereby delaying the scheduled mid-year redetermination originally scheduled to occur on or about November 1, 2009. With respect to any scheduled redeterminations in subsequent years, however, the Redetermination Date continues to be on or about May 1 and November 1 of each such year.
Pursuant to the Seventh Amendment, should there be a borrowing base deficiency after the scheduled redetermination on or about November 30, 2009, the Company will have 30 days to eliminate such deficiency.
On December 1, 2009, the Company and the other parties to the Credit Facility entered into the Eighth Amendment to the Credit Facility (the “Eighth Amendment”), pursuant to which the Credit Facility was amended, among other things, to revise the definition of “Redetermination Date” with respect to scheduled redeterminations for the year ended December 31, 2009 to be on or about May 1 of each year, thereby removing the scheduled redetermination previously scheduled to occur on or about November 30, 2009, and with respect to scheduled redeterminations for the year ended December 31, 2010 to be on or about January 30, May 1 and November 1 of such year. With respect to any scheduled redeterminations in subsequent years, however, the Redetermination Date continues to be on or about May 1 and November 1 of each such year. Should there be a borrowing base deficiency after the scheduled redetermination on oar about January 30, the Company will have 30 days to eliminate such deficiency. In addition to the scheduled redeterminations, the Company is permitted to request a special redetermination of the borrowing base once between each scheduled redetermination and the Lenders are permitted to request a special redetermination of the borrowing base once between each scheduled redetermination. Additionally the Credit Facility permits the Company to terminate the engagement of its financial consultant and advisor effective as of November 29, 2009, subject to certain conditions.
On February 1, 2010, we entered into the Ninth Amendment to Credit Facility, pursuant to which our Credit Facility was amended to, among other things, (i) remove the scheduled redetermination of the borrowing base on or about January 30, 2010 with the effect that scheduled redeterminations for the year ended December 31, 2010 revert to the regular redetermination schedule of every six months on or about May 1 and November 1 of each year and (ii) reduce the borrowing base to $16 million from $35 million by incremental fixed amount in connection with certain contemplated asset sales, and, effective as of April 1, 2010, to automatically reduce to $16 million, regardless of whether any of the contemplated asset
sales were consummated. The Ninth Amendment also provided for the release of certain liens relating to the Assets that secure the Company’s obligations under the Credit Facility. Effective February 26, 2010, in connection with the consummation of the sale of our gathering assets and the application of the proceeds therefrom to pay down outstanding borrowings, we elected to reduce the borrowing base to $16 million effective immediately. Following the $23 million debt repayment, our available credit is approximately $4.0 million.
The Ninth Amendment also increased the interest rate pricing grid by 25 basis points for Eurodollar based loans and for alternate base rate (“ABR”) priced loans effective February 1, 2010. Interest on borrowings under the Credit Facility accrues at variable interest rates at either a Eurodollar rate or an ABR. The Eurodollar rate is calculated as LIBOR plus an applicable margin that, as amended, varies from 2.75% (for periods in which the Company has utilized less than 50% of the borrowing base) to 3.75% (for periods in which the Company has utilized at least 90% of the borrowing base). The ABR, as amended, is equal to the sum of (i) the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50% and (c) the Adjusted LIBO Rate for a one month interest period on such day plus 1.00% and (ii) an applicable margin that varies from 1.75% (for periods in which the Company has utilized less than 50% of the borrowing base) to 2.75% (for periods in which the Company has utilized at least 90% of the borrowing base). The Ninth Amendment further provides that if the borrowing base is greater than $16,000,000 on March 1, 2010, then effective on and after such date the interest rate pricing grid will automatically increase an additional 25 basis points for Eurodollar based loans and for ABR priced loans. The Company elects the basis of the interest rate at the time of each borrowing under the Credit Facility. However, under certain circumstances, the Lenders may require the Company to use the non-elected basis in the event that the elected basis does not adequately and fairly reflect the cost of making such loans.
NOTE 9 - 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.
NOTE 10 - FAIR VALUE MEASUREMENTS
Effective January 1, 2008, the Company adopted the authoritative guidance that applies to all financial assets and liabilities required to be measured and reported on a fair value basis. Beginning January 1, 2009, the Company also applied the guidance to non-financial assets and liabilities. The guidance establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
Level 1: Quoted prices are available in active markets for identical assets or liabilities;
Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; or
Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.
The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2009 by level within the fair value hierarchy:
As of December 31, 2009, the Company’s derivative financial instruments are comprised of two natural gas swap agreements. The fair values of the swap agreements are determined based primarily on inputs that are derived from observable data at commonly quoted intervals for the full term of the derivatives and are therefore considered level 2 in the fair value hierarchy. Until May 2009, the Company’s derivative financial instruments also included a costless collar agreement. The fair value of the costless collar agreement was determined based on both observable and unobservable pricing inputs and therefore, the data sources utilized in this valuation model was considered level 3 inputs in the fair value hierarchy. The counterparty in all of the Company’s derivative financial instruments is the Administrative Agent under the Credit Facility. See Note 8 “Credit Facility” herein.
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as level 3 in the fair value hierarchy:
Fair value used in the initial recognition of asset retirement obligations is determined based on the present value of expected future dismantlement costs incorporating our estimate of inputs used by industry participants when valuing similar liabilities. Accordingly, the fair value is based on unobservable pricing inputs and therefore, is considered a level 3 value input in the fair value hierarchy.
Other financial instruments not measured at fair value on a recurring basis include cash and cash equivalents, accounts receivable, note receivable, accounts payable, accrued liabilities, Convertible Notes and long-term debt. With the exception of the note receivable, Convertible Notes and long-term debt, the financial statement carrying amounts of these items approximate their fair values due to their short-term nature. The carrying amount of long-term debt approximates the fair value due to its floating rate structure. The carrying amount of the Company’s note receivable approximates fair value based on current interest rates for similar instruments. Estimated fair values for Convertible Notes of $40,218,750
and $39,081,250 as of December 31, 2009 and 2008, respectively, have been determined using recent market quotes.
NOTE 11 - STOCKHOLDERS’ EQUITY (DEFICIT)
The Company’s capital stock as of December 31, 2009 and 2008 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, 2009 and 2008, Gasco had no shares of Series B Preferred Stock (“Preferred Stock”) issued and outstanding.
Common Stock - Gasco has 107,715,897 shares of common stock issued and outstanding and 73,700 shares held in treasury as of December 31, 2009. 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. 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, 2009, we had 12,096,672 shares of common stock issuable upon exercise of outstanding options. Additional options may be granted to purchase 1,275,918 shares of common stock under our stock option plan and an additional 326,750 shares of common stock are issuable under our restricted stock plan. As of December 31, 2009, 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 123,965,897 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 2009 and 2008 are described as follows:
During the years ended December 31, 2009 and 2008, the Company’s Board of Directors approved the issuance of 7,500 and 49,000 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 2009 and 2008, 6,301 and 11,521 shares of the Company’s common stock were cancelled in satisfaction of the income tax liability of $3,566 and $18,036, respectively, associated with the vesting of restricted stock.
NOTE 12 - STATEMENT OF CASH FLOWS
During the year ended December 31, 2009, the Company’s non-cash investing and financing activities consisted of the following transactions:
During the year ended December 31, 2008, the Company’s non-cash investing and financing activities consisted of the following transactions:
During the year ended December 31, 2007, the Company’s non-cash investing and financing activities consisted of the following transactions:
Cash paid for interest during the years ended December 31, 2009, 2008 and 2007 was $5,356,086, $4,287,996 and $4,304,308, respectively. There was no cash paid for income taxes during the years ended December 31, 2009, 2008 and 2007.
NOTE 13 - INCOME TAXES
The provision (benefit) for income taxes for the years ended December 31, 2009, 2008 and 2007 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, 2009, 2008 and 2007 is summarized below:
The components of the deferred tax assets and liabilities as of December 31, 2009 and 2008 are as follows:
The Company has $183,297,495 of net operating loss carryover for federal income tax purposes as of December 31, 2009, of which $4,560,920 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. The Company has $129,602,677 of net operating loss carryover for state income tax purposes as of December 31, 2009, 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, 2029. A portion of the net operating loss carryovers begins expiring in 2019. The Company provided a valuation allowance against its net deferred tax asset of $86,968,454 and $66,809,388 as of December 31, 2009 and 2008, respectively, since it believes that it is more likely than not that the net deferred tax assets will not be fully realized on future income tax returns. The decrease and increase in the valuation allowance for 2009 and 2008 is $20,159,066 and $(19,366,969), respectively.
NOTE 14 - RELATED PARTY TRANSACTIONS
During the year ended December 31, 2007, 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, 2008.
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 15 - COMMITMENTS
The Company leases approximately 11,840 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 $151,200 per year. The Company’s future rental payments due under this lease are
$85,491 which will be due during 2010. During February 2010, the Company extended its lease until May 31, 2011. The annual rental expense under the extension is approximately $165,600.
Rent expense for the years ended December 31, 2009, 2008 and 2007 was $187,335, $169,549 and $137,512, 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.
As of December 31, 2009, the Company had employment agreements with its three key officers through January 31, 2011. Total minimum compensation under these agreements is $350,000 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 of $250,000. Included in the employment agreements is a bonus calculation for each of the covered officers totaling 1.25% of a defined cash flow figure based on net after tax earnings adjusted for certain expenses. These employment agreements were amended on January 1, 2009 and on January 22, 2009 to among other things, (i) provide for the forfeit of any right to the annual incentive bonus compensation due to the executive if such executive does not remain employed by the Company through receipt of the signed audit letter relating to such year and (ii) provide for a cash payment, upon termination of such executive’s employment without cause or a change in control of the Company, to the executive in an amount equal to twice the amount paid to such executive as annual bonus compensation for the previous fiscal year.
In January 2010, in connection with the resignation of President and CEO, the Company terminated his employment agreement and entered into a consulting agreement under which the Company will make payments to him totaling $1,150,000 through March 1, 2011. Additionally, all of his outstanding options to purchase common stock became vested in January 2010. As a result of the acceleration of the vesting of his options, the Company will recognize approximately $132,000 in additional stock compensation expense during the first quarter of 2010.
During April 2009, the Company entered into a firm sales and transportation agreement to sell up to 50,000 MMBtu per day of its 2010 and 2011 gross production from the Uinta Basin. The contract contains two pricing mechanisms: (1) up to 25,000 MMBtu per day will be priced at the NW Rockies first of month price and (2) up to 25,000 MMBtu per day will be priced at the first of the month index price as published by Gas Daily for the North West Wyoming Poll Index price.
As discussed in Note 2 - “Significant Accounting Policies” herein, we have entered into derivative contracts relating to a portion of our natural gas production for 2010 and through March 2011.
NOTE 16 - 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 $116,595, $150,617 and $143,293 during the years ended December 31, 2009, 2008 and 2007, respectively.
NOTE 17 - SELECTED QUARTERLY INFORMATION (Unaudited)
The following represents selected quarterly financial information for the years ended December 31, 2009 and 2008. During the fourth quarter of 2009, the Company was actively engaged in marketing for sale its gathering assets and water disposal facilities. In February 2010, the Company entered into an asset purchase agreement to sell its gathering assets and water disposal facilities for total cash consideration of $23,000,000 subject to certain adjustments. The net loss for the fourth quarter of 2009 includes an impairment loss of $1,373,799 related to these assets held for sale.
(a)
The net loss for the first quarter of 2009 includes a $41,000,000 property impairment related to the Company’s oil and gas properties as further discussed in Note 2 of the accompanying consolidated financial statements.
(b)
As discussed in Note 3 “Change in Method of Determining Oil and Gas Reserves”, effective December 31, 2009, the Company changed its method of determining the quantities of oil and gas reserves which affected the amount of depreciation, depletion and amortization and the ceiling test calculation for oil and gas properties in the fourth quarter of 2009.
(c)
The Form 10-Q’s for the first three quarters of 2008 reflected derivative gains (losses) and interest income as revenue. During the fourth quarter of 2008 the Company reclassified these amounts from revenue to other income (expense) in the accompanying consolidated statements of operations. The amounts in the table above reflect this reclassification for all periods presented.
NOTE 18- LEGAL PROCEEDINGS
The Company is party to various litigation matters arising out of the normal course of business. The more significant litigation matters are summarized below. The ultimate outcome of these matters cannot
presently be determined, nor can the liability that could potentially result from an adverse outcome be reasonably estimated at this time. The Company does not expect that the outcome of these proceedings will have a material adverse effect on its financial position, results of operations or cash flow.
EPA Enforcement Action
In early 2007, a consultant to Riverbend Gas Gathering, LLC (“Riverbend”), a wholly-owned subsidiary of the Company, who 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 Riverbend 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 (“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. Riverbend’s June 22 letter voluntarily disclosed the potential violations to 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 has continued to work with the EPA and the Department of Justice on a settlement of this matter, and it anticipates that such a resolution will be achieved during 2010. Although the Company is unable to estimate a range of possible costs, the Company 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 penalty that may be assessed in conjunction with a resolution of this matter will not materially affect the Company’s financial position or liquidity. The compliance costs could, however, materially affect the Company’s results of operations for a particular period.
Sweeney Litigation
On December 5, 2008, a lawsuit was filed in state court in Cook County, Illinois (“Sweeney litigation”) by eleven individual plaintiffs and Griffin Asset Management, LLC. The lawsuit alleges that defendants Richard N. Jeffs (“Jeffs), Marc Bruner (“Bruner”) and the Company through its agency with Bruner, made misrepresentations, committed fraud, aided and abetted a scheme to defraud, and conspired to defraud in connection with the plaintiffs’ investment in Brek Energy Corporation (“Brek”). The complaint alleges that plaintiffs’ relied on various misrepresentations and omissions by the individual defendants when making the decision to invest in Brek, which merged into the Company in December of 2007. Plaintiffs sought unspecified damages in an amount in excess of $50,000, punitive damages, attorneys’ fees, and costs. The Company removed the case to the United States District Court for the Northern District of Illinois, Eastern Division, on January 7, 2009 and answered the complaint, denying all liability, on February 13, 2009. A scheduling conference was held on April 1, 2009. The judge ordered fact discovery in the case to be completed by December 15, 2009 and set the trial for June 7, 2010. Following the scheduling conference, Jeffs was served with the complaint and filed a motion to dismiss all counts against him on the grounds that certain claims are barred by limitations, that plaintiffs lack standing to bring other claims, and that plaintiffs have failed to join an indispensable party (Brek).
During the fall of 2009, the parties began to engage in the early stages of discovery and numerous depositions were scheduled for late November and the first half of December, 2009. Prior to the start of depositions, however, on November 25, 2009, the parties reached an agreement in principle to settle the claims made against the Company and Bruner in the Sweeney litigation.
On December 4, 2009, while counsel for the Company was documenting the partial settlement, counsel for Jeffs sent a letter to the Company demanding that the Company (1) reimburse Jeffs for his defense costs to date in the Sweeney litigation; and (2) indemnify Jeffs for any judgment entered (or settlement made) in the Sweeney litigation. Jeffs’ counsel claimed that Jeffs was entitled to such reimbursement and indemnification under the bylaws of Brek Energy Corporation that were in effect at the time of Brek’s merger into a wholly-owned subsidiary of the Company.
On December 9, 2009, Jeffs also filed an action in Colorado federal district court to obtain a declaration that the 550,000 shares of the Company’s stock being held in escrow under an agreement between the Company and Jeffs belong to, and should be released to, Jeffs pursuant to the terms of the escrow agreement (“Jeffs litigation”).
On or around December 18, counsel for the Company, Bruner, Jeffs, and plaintiffs reached an agreement in principle to settle all claims in both the Sweeney litigation and the Jeffs litigation. This global settlement was documented and finalized in February, 2010.
On February 5, 2010, counsel for the Company, Bruner, Jeffs, and plaintiffs filed an Agreed Motion for Dismissal with Prejudice of the Sweeney litigation. On February 9, 2010, the United States District Court for the Northern District of Illinois, Eastern Division entered a docket entry granting the parties’ Agreed Motion and dismissing the Sweeney litigation with prejudice. On February 16, 2010, counsel for Gasco and Jeffs filed an Agreed Motion for Dismissal with Prejudice of the Jeffs litigation. On February 17, 2010, the United States District Court for the District of Colorado entered an Order of Dismissal with Prejudice. A settlement payment, which was accrued in the accompanying financial statements, was made on February 17, 2010, following this dismissal with prejudice.
NOTE 19 - CONSOLIDATING FINANCIAL STATEMENTS
On August 22, 2008, Gasco filed a Form S-3 shelf registration statement with the SEC. Under this registration statement, which was declared effective on September 8, 2008, Gasco may from time to time offer and sell securities including common stock, preferred stock, depositary shares and debt securities that may be fully, irrevocably and unconditionally guaranteed by all of its subsidiaries: Gasco Production Company, San Joaquin Oil & Gas, Ltd., Riverbend Gas Gathering, LLC and Myton Oilfield Rentals, LLC (collectively, the “Guarantor Subsidiaries”). Set forth below are the condensed consolidating financial statements of Gasco, which is referred to as the Parent, and the Guarantor Subsidiaries. In accordance with US GAAP the financial statements of the Parent would include an investment in its subsidiaries and the subsidiaries would include general and administrative expenses. These condensed statements are presented for information purposes only and do not purport the Parent’s balance sheet or statement of operations are prepared under US GAAP.
Condensed Consolidating Balance Sheet
As of December 31, 2009
(Unaudited)
Condensed Consolidating Balance Sheet
As of December 31, 2009
(Unaudited)
Condensed Consolidating Balance Sheet
As of December 31, 2008
(Unaudited)
Condensed Consolidating Balance Sheet
As of December 31, 2008
(Unaudited)
Consolidating Statements of Operations
(Unaudited)
Consolidating Statements of Operations
(Unaudited)
Consolidating Statements of Cash Flows
(Unaudited)
Consolidating Statements of Cash Flows
(Unaudited)
Consolidating Statements of Cash Flows
(Unaudited)
Consolidating Statements of Cash Flows
(Unaudited)
NOTE 20 - 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, 2009, 2008 and 2007 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). As discussed in Note 3 “Change in Method of Determining Oil and Gas Reserves”, effective December 31, 2009, the rules relating to oil and gas reserve estimates were revised. The revised rules included a change in pricing used to prepare reserve estimates, the inclusion of non-traditional resources in reserves, the allowance for new technologies in determining reserves and the definitions of proved reserves were revised. Prior to December 31, 2009, this calculation was performed using year-end oil and gas prices. Effective December 31, 2009, the SEC issued new guidance requiring the use of the average, first-of-the-month price rather than the prices on the last day of the year. The oil and gas prices weighted by production over the lives of the proved reserves used as of December 31, 2009, 2008 and 2007 were $44.46 per bbl of oil and $2.85 per Mcf of gas, $15.33 per bbl of oil and $4.63 per Mcf of gas and $73.95 per bbl of oil and $6.53 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. The Company does not believe that provisions of the new rules, other than pricing, significantly impacted the reserve estimates. The Company does not believe that it is practicable to estimate the effect of applying the new rules on the following tables for reserve quantities or standardized measure of discounted cash flows for the year ended December 31, 2009.
Reserve Quantities
Standardized Measure of Discounted Future Net Cash Flows
Changes in the Standardized Measure of Discounted Future Net Cash Flows
NOTE 20 - SUBSEQUENT EVENTS
Sale of Gathering Assets
On February 26, 2010, we completed the sale (the “Closing”) of materially all of the assets (the “Asset Sale”) comprising our gathering system and our evaporative facilities, located in Uintah County, Utah (the “Gathering Assets”), to Monarch Natural Gas, LLC (“Monarch”) pursuant to an Asset Purchase Agreement dated January 29, 2010 (the “Purchase Agreement”). At Closing, we received total cash consideration of $23 million from Monarch, the entirety of which was used to repay amounts outstanding under our Credit Facility (defined below).
Pursuant to the Purchase Agreement, simultaneous with Closing we entered into (i) a transition services agreement with Monarch pursuant to which we will provide certain services relating to the operation of the Gathering Assets to Monarch for a six-month term commencing at Closing; (ii) a gas gathering agreement with Monarch pursuant to which we dedicated our natural gas production from all of our Utah
acreage and Monarch will provide gathering, compression and processing services utilizing the Gathering Assets to us; and (iii) a salt water disposal services agreement with Monarch pursuant to which we may deliver salt water produced by our operations to the evaporative facilities that Monarch acquired in the Asset Sale. These agreements will result in less revenue and additional costs with an aggregate annual impact, inclusive of a reduction in depreciation expense, of approximately $3.5 million based on 2009 activity. The Purchase Agreement is subject to customary post-closing terms and conditions for transactions of this size and nature.
Acquisition of Petro-Canada
On February 25, 2010, we completed the acquisition of certain oil and gas leases and lands (the “Petro-Canada Assets”) from Petro-Canada Resources (USA) Inc., a Colorado corporation (“Petro-Canada”), for a purchase price of approximately $482,000, subject to customary post-closing terms and conditions for transactions of this size and nature. The sale was made pursuant to a definitive agreement dated February 4, 2010 by and between us and Petro-Canada. The Petro-Canada Assets include one producing well, on shut-in well with recompletion potential and 5,582 gross and net acres located in Utah west of our Gate Canyon operating area. We funded this acquisition with cash flow from operating activities.
Amendment to Credit Facility
On February 1, 2010, our $250 million revolving credit facility (the “Credit Facility”) was amended to, among other things, incrementally reduce our borrowing base by a fixed amount in connection with certain contemplated asset sales, including the sale of the Gathering Assets described above, and, effective as of April 1, 2010, to automatically reduce to $16 million, regardless of whether any of the contemplated asset sales were consummated. Effective February 26, 2010, in connection with the consummation of the Asset Sale and the application of the proceeds therefrom to pay down outstanding borrowings under our revolving credit facility, we elected to reduce the borrowing base to $16 million effective immediately. Following the $23 million debt repayment, our available credit is approximately $4.0 million.
Resignation of Former Chief Executive Officer; Appointment of Replacement
Effective January 27, 2010, our former Chief Executive Officer and President, Mark Erickson, resigned and was replaced by Charles Crowell as interim Chief Executive Officer and W. King Grant as President.
ITEM 9
ITEM 9
- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
Disclosure Controls and Procedures
As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our management, as appropriate, to allow such persons to make timely decisions regarding required disclosures.
Based upon the results of our evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2009.
Changes in Internal Controls over Financial Reporting during the Fourth Quarter of 2009
There have not been any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated by the SEC under the Securities Exchange Act of 1934) during our most recently completed fiscal quarter 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, 2009. 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, 2009.
The effectiveness of internal control over financial reporting as of December 31, 2009, was audited by KPMG LLP, the independent registered public accounting firm who audited our financial statements for the year ended December 31, 2009, as stated in its report that follows.
Pursuant to the requirements of Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934 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, 2010.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Gasco Energy, Inc.:
We have audited Gasco Energy, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, 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, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gasco Energy, Inc. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended, and our report dated March 3, 2010 expressed an unqualified opinion on those consolidated financial statements.
Denver, Colorado
March 3, 2010
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 2010 Annual Meeting of Shareholders to be filed with the SEC pursuant to Regulation 14A, which information is incorporated herein by reference.
The information required by this item will be included in the definitive proxy statement of Gasco relating to the Company’s 2010 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 2010 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 2010 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 2010 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
The following is a list of exhibits filed or furnished (as indicated) as part of this 10-K. Where so noted, exhibits which were previously filed are incorporated herein by reference.
(a)
1. See “Index to Financial Statements” under Item 8 on page 68.
2. Financial Statement Schedules - none.
3. Exhibits - See Index to Exhibits, below.
INDEX TO EXHIBITS
1.1
Underwriting Agreement dated April 13, 2007, between Gasco Energy, Inc. and JP Morgan Securities Inc. (incorporated herein 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).
3.1
Amended and Restated Articles of Incorporation (incorporated herein 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 herein 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 herein 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
Second Amended and Restated Bylaws of Gasco Energy, Inc., dated April 8, 2009 (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K dated April 8, 2009, filed on April 8, 2009, File No. 001-32369).
3.5
Certificate of Designation for Series B Convertible Preferred Stock (incorporated herein 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
Indenture dated as of October 20, 2004, between Gasco Energy, Inc. and Wells Fargo Bank, National Association, as Trustee (incorporated herein 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).
4.2
Form of Global Note representing $65 million principal amount of 5.5% Convertible Senior Notes due 2011 (incorporated herein by reference to Exhibit A to Exibit 4.1 to the Company’s Current Report on Form 8-K filed on October 20, 2004, File No. 000-26321).
4.3
Registration Rights Agreement dated October 20, 2004, among Gasco Energy, Inc., J.P. Morgan Securities Inc. and First Albany Capital Inc (incorporated herein 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).
4.4
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 herein by reference to Exhibit 4.2 to the Company’s Form 8-K dated March 29, 2006, filed March 31, 2006, File No. 001-32369).
4.5
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 herein by reference to Exhibit 4.1 to the Company’s Form 8-K dated March 29, 2006, filed March 31, 2006, File No. 001-32369).
4.6
First Amendment to the Credit Agreement dated April 22, 2008 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 herein by reference to Exhibit 4.13 to the Company’s Form 10-Q dated March 31, 2008, filed May 6, 2008, File No. 001-32369).
4.7
Second Amendment to the Credit Agreement, dated as of December 10, 2008, by and among by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated December 12, 2008, filed on December 12, 2008, File No. 001-32369).
4.8
Third Amendment to the Credit Agreement, dated as of May 14, 2009, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party hereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated May 15, 2009, File No. 001-32369).
4.9
Fourth Amendment to the Credit Agreement, dated as of July 6, 2009, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to the Company’s Form 8-K dated July 7, 2009, File No. 001-32369).
4.10
Fifth Amendment to the Credit Agreement, dated as of August 28, 2009, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to the Company’s Form 8-K dated August 31, 2009, File No. 001-32369).
4.11
Sixth Amendment to the Credit Agreement, dated as of September 30, 2009, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to the Company’s Form 8-K dated October 1, 2009, File No. 001-32369).
4.12
Seventh Amendment to the Credit Agreement, dated as of October 30, 2009, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to the Company’s Form 10-Q dated September 30, 2009, File No. 001-32369).
4.13
Eighth Amendment to the Credit Agreement, dated as of December 1, 2009, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to the Company’s Form 8-K dated December 1, 2009, File No. 001-32369).
4.14
Ninth Amendment to the Credit Agreement, dated as of February 1, 2010, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to the Company’s Form 8-K dated February 1, 2010, File No. 001-32369).
4.15
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 herein 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).
# 10.1
1999 Stock Option Plan (incorporated herein 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 herein 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 herein 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 (incorporated herein by reference to 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 (incorporated herein by reference to 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 (incorporated herein by reference to 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 (incorporated herein by reference to 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).
#10.10
Employment Agreement dated February 14, 2005 by and between Gasco Energy, Inc. and W. King Grant (incorporated herein 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).
#10.11
Form of Amendment to Gasco Energy, Inc. Employment Agreement, dated as of December 31, 2008, and effective as of January 1, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated January 7, 2009, filed January 7, 2009, File No. 001-32369).
#10.12
Form of Second Amendment to Gasco Energy, Inc. Employment Agreement, dated as of January 22, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated herein by reference to Exhibit 10.12 to the Company’s Form 10-K for the fiscal year ended December 31, 2008, File No. 001-32369).
10.13
Asset Purchase Agreement dated January 29, 2010 by and among Gasco Energy, Inc., Riverbend Gas Gathering, LLC, and Monarch Natural Gas, LLC (incorporated herein by reference to Exhibit 10.1 to Gasco Energy, Inc.’s Current Report on Form 8-K filed on February 3, 2010).
10.14
Consulting Agreement and Release, dated January 29, 2010, by and between Gasco Energy, Inc. and Mark A. Erickson (incorporated herein by reference to Exhibit 10.1 to Gasco Energy, Inc.’s Current Report on Form 8-K filed on February 1, 2010).
10.15
Gas Gathering and Processing Agreement, effective March 1, 2010, by and between Gasco Production Company and Monarch Natural Gas, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 3, 2010).
*23.1
Consent of Netherland, Sewell & Associates, Inc.
*23.2
Consent of KPMG
*31
Rule 13a-14(a)/15d-14(a) Certifications
*32
Section 1350 Certifications
*99.1
Report of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists.
*
Filed herewith.
#
Identifies management contracts and compensatory plans or arrangements.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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
1.1
Underwriting Agreement dated April 13, 2007, between Gasco Energy, Inc. and JP Morgan Securities Inc. (incorporated herein 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).
3.1
Amended and Restated Articles of Incorporation (incorporated herein 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 herein 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 herein 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
Second Amended and Restated Bylaws of Gasco Energy, Inc., dated April 8, 2009 (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K dated April 8, 2009, filed on April 8, 2009, File No. 001-32369).
3.5
Certificate of Designation for Series B Convertible Preferred Stock (incorporated herein 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
Indenture dated as of October 20, 2004, between Gasco Energy, Inc. and Wells Fargo Bank, National Association, as Trustee (incorporated herein 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).
4.2
Form of Global Note representing $65 million principal amount of 5.5% Convertible Senior Notes due 2011 (incorporated herein by reference to Exhibit A to Exibit 4.1 to the Company’s Current Report on Form 8-K filed on October 20, 2004, File No. 000-26321).
4.3
Registration Rights Agreement dated October 20, 2004, among Gasco Energy, Inc., J.P. Morgan Securities Inc. and First Albany Capital Inc (incorporated herein 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).
4.4
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 herein by reference to Exhibit 4.2 to the Company’s Form 8-K dated March 29, 2006, filed March 31, 2006, File No. 001-32369).
4.5
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 herein by reference to Exhibit 4.1 to the Company’s Form 8-K dated March 29, 2006, filed March 31, 2006, File No. 001-32369).
4.6
First Amendment to the Credit Agreement dated April 22, 2008 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 herein by reference to Exhibit 4.13 to the Company’s Form 10-Q dated March 31, 2008, filed May 6, 2008, File No. 001-32369).
4.7
Second Amendment to the Credit Agreement, dated as of December 10, 2008, by and among by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated December 12, 2008, filed on December 12, 2008, File No. 001-32369).
4.8
Third Amendment to the Credit Agreement, dated as of May 14, 2009, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party hereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated May 15, 2009, File No. 001-32369).
4.9
Fourth Amendment to the Credit Agreement, dated as of July 6, 2009, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to the Company’s Form 8-K dated July 7, 2009, File No. 001-32369).
4.10
Fifth Amendment to the Credit Agreement, dated as of August 28, 2009, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to the Company’s Form 8-K dated August 31, 2009, File No. 001-32369).
4.11
Sixth Amendment to the Credit Agreement, dated as of September 30, 2009, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to the Company’s Form 8-K dated October 1, 2009, File No. 001-32369).
4.12
Seventh Amendment to the Credit Agreement, dated as of October 30, 2009, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to the Company’s Form 10-Q dated September 30, 2009, File No. 001-32369).
4.13
Eighth Amendment to the Credit Agreement, dated as of December 1, 2009, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to the Company’s Form 8-K dated December 1, 2009, File No. 001-32369).
4.14
Ninth Amendment to the Credit Agreement, dated as of February 1, 2010, by and among Gasco Energy, Inc., as Borrower, certain subsidiaries of Gasco Energy, Inc., as Guarantors, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to the Company’s Form 8-K dated February 1, 2010, File No. 001-32369).
4.15
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 herein 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).
# 10.1
1999 Stock Option Plan (incorporated herein 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 herein 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 herein 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 (incorporated herein by reference to 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 (incorporated herein by reference to 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 (incorporated herein by reference to 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 (incorporated herein by reference to 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).
#10.10
Employment Agreement dated February 14, 2005 by and between Gasco Energy, Inc. and W. King Grant (incorporated herein 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).
#10.11
Form of Amendment to Gasco Energy, Inc. Employment Agreement, dated as of December 31, 2008, and effective as of January 1, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K dated January 7, 2009, filed January 7, 2009, File No. 001-32369).
#10.12
Form of Second Amendment to Gasco Energy, Inc. Employment Agreement, dated as of January 22, 2009, by and among Gasco Energy, Inc. and certain of its Executives (incorporated herein by reference to Exhibit 10.12 to the Company’s Form 10-K for the fiscal year ended December 31, 2008, File No. 001-32369).
10.13
Asset Purchase Agreement dated January 29, 2010 by and among Gasco Energy, Inc., Riverbend Gas Gathering, LLC, and Monarch Natural Gas, LLC (incorporated herein by reference to Exhibit 10.1 to Gasco Energy, Inc.’s Current Report on Form 8-K filed on February 3, 2010).
10.14
Consulting Agreement and Release, dated January 29, 2010, by and between Gasco Energy, Inc. and Mark A. Erickson (incorporated herein by reference to Exhibit 10.1 to Gasco Energy, Inc.’s Current Report on Form 8-K filed on February 1, 2010).
10.15
Gas Gathering and Processing Agreement, effective March 1, 2010, by and between Gasco Production Company and Monarch Natural Gas, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 3, 2010).
*23.1
Consent of Netherland, Sewell & Associates, Inc.
*23.2
Consent of KPMG
*31
Rule 13a-14(a)/15d-14(a) Certifications
*32
Section 1350 Certifications
*99.1
Report of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists.
*
Filed herewith.
#
Identifies management contracts and compensatory plans or arrangements.