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Kodiak Oil 10-Q 2007
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2007
Commission File No. 001-32920
(Exact name of registrant as specified in its charter)
1625 Broadway, Suite 330 Denver, Colorado 80202 (Address of principal executive offices, including zip code)
303-592-8075 (Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
87,573,426 shares of no par value of the Registrant’s Common Stock were issued and outstanding as of April 30, 2007. ___________________________
KODIAK OIL & GAS CORP. FORM 10-Q TABLE OF CONTENTS
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PART 1 - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS
KODIAK OIL & GAS CORP. CONSOLIDATED BALANCE SHEETS
SEE ACCOMPANYING NOTES
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KODIAK OIL & GAS CORP. CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
SEE ACCOMPANYING NOTES
2
KODIAK OIL & GAS CORP. STATEMENT OF STOCKHOLDERS’ EQUITY (UNAUDITED)
SEE ACCOMPANYING NOTES
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KODIAK OIL & GAS CORP. CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
SEE ACCOMPANYING NOTES
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KODIAK OIL & GAS CORP. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Organization
Description of Operations
Kodiak Oil & Gas Corp. and its subsidiary (“Kodiak” or the “Company”) is a public company listed for trading on the American Stock Exchange (AMEX) whose corporate headquarters are located in Denver, Colorado, USA. The Company is an independent energy company engaged in the exploration, exploitation, development, acquisition and production of natural gas and crude oil entirely in the western United States.
The Company was incorporated (continued) in the Yukon Territory on September 28, 2001.
Note 2 – Basis of Presentation and Significant Accounting Policies
Basis of Presentation
The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc. All significant inter-company balances and transactions have been eliminated. The majority of the Corporation’s business is transacted in US dollars and, accordingly, the financial statements are expressed in US dollars. The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles for interim financial information. Accordingly, they do not include all of the information and footnotes required by U. S. generally accepted accounting principles for complete financial statements. In the opinion of management, the consolidated financial statements contain all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation of the Company’s results for the periods presented. These consolidated financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.
Certain amounts in the 2006 unaudited consolidated financial statements have been reclassified to conform to the 2007 unaudited consolidated financial statement presentation; such reclassifications had no effect on the 2006 net loss.
Use of Estimates in the Preparation of Financial Statements
The preparation of the financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, 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. The Company bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes that its estimates are reasonable.
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Cash and Cash Equivalents
Cash and cash equivalents consist of all highly liquid investments that are readily convertible to cash and have maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.
Restricted Investment
The restricted investment balance as of March 31, 2007 and December 31, 2006 is comprised of: (a) $175,000 certificate of deposit to collateralize a surety bond to provide for state bonding requirements for plugging and abandonment liabilities; and (b) $42,400 certificate of deposit to collateralize the costs of office improvements that will be released over the four year remaining term of the lease at $10,600 per year. Subsequent to period end, the Company increased the certificate of deposit to collateralize the office improvements for the new leased space to $67,797.
Concentration of Credit Risk
The Company’s cash equivalents and short-term investments are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds 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.
Oil and Gas Producing Activities
The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition and exploration activities. Proceeds from property sales are generally credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full costs pool.
Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.
For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil.
Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value,
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discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost, or estimated fair value, if lower of unproved properties. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net revenues is computed by applying current prices of oil and gas 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.
As of December 31, 2006, based on oil and gas prices of $50.37 per barrel and $4.53 per Mcf, the full cost pool would have exceeded the above described ceiling by $5,219,276. However, subsequent to year end, oil and gas prices increased and the Company completed a well with additional reserves; using these prices, the Company’s full cost pool would not have exceeded the ceiling limitation. As a result of the increase in the ceiling amount using subsequent prices and an estimate of the additional proved reserves, the Company did not record an impairment of its oil and gas prices at December 31, 2006. As of March 31, 2007, the Company’s full cost pool exceeded the ceiling limitation based on oil and gas prices of $55.12 per barrel and $4.16 per Mcf. Subsequent commodity price increases were not sufficient to eliminate the need for the impairment and therefore, impairment expense of $14,000,000 was recorded during the quarter ended March 31, 2007.
Estimated reserve quantities and future net cash flows have the most significant impact on the Company because these reserve estimates are used in providing a measure of the Company’s overall value. These estimates are also used in the quarterly calculations of depletion, depreciation and impairment of the Company’s proved properties.
Estimating accumulations of gas and oil is complex and is not exact 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 Securities and Exchange Commission (“SEC”), such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of 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 the Company’s wells have been producing less than six years, their production history is 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 the Company’s estimates of proved reserves including developed producing, developed non-producing and undeveloped. As the Company’s 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.
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 the Company’s estimates. Any significant variance could materially affect the quantities and present value of the Company’s reserves. For example, a decrease in price of $0.10 per Mcf for natural gas and $1.00 per barrel of oil would result in a decrease in the Company’s December 31, 2006 present value of future net cash flows of approximately $763,000. In addition, the Company may adjust estimates of proved reserves to reflect production history, acquisitions, divestitures, ownership interest revisions, results of
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exploration and development and prevailing gas and oil prices. The Company’s reserves may also be susceptible to drainage by operators on adjacent properties.
Other Property and Equipment
Other property and equipment such as office furniture and equipment, vehicles, and computer hardware and software are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is recorded using the straight-line method over the estimated useful lives of three years for computer equipment, and five years for office equipment and vehicles. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.
Fair Value of Financial Instruments
The Company’s financial instruments including cash and cash equivalents, accounts receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments.
Stock-Based Compensation
The Company has historically accounted for stock-based compensation under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123, Accounting for Stock-Based Compensation. This statement requires us to record an expense associated with the fair value of stock-based compensation. We currently use the Black-Scholes option valuation model to calculate stock based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate.
On January 1, 2006, we adopted SFAS No. 123(R), “Accounting for Stock-Based Compensation,” using the modified prospective method. Under the modified prospective method, the adoption of SFAS No. 123(R) applies to new awards and to awards modified, repurchased, or cancelled after December 31, 2005, as well as to the unvested portion of awards outstanding as of January 1, 2006. In accordance with the modified prospective method, we have not adjusted the financial statements for periods ended prior to January 1, 2006. We did not recognize any one time effects of the adoption and continued to use similar option valuation models and assumptions as were used prior to January 1, 2006. There is no fair-value-based compensation expense associated with prior awards that were not vested on the date of the adoption of SFAS No. 123(R).
Asset Retirement Obligation
The Company follows SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs. The future cash outflows associated with settling the asset retirement obligations that have been accrued in the accompanying balance sheets are excluded from the ceiling test calculations. The Company also depletes the estimated dismantlement and abandonment costs, net of salvage values,
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associated with future development activities that have not yet been capitalized as asset retirement obligations. These costs are also included in the ceiling test calculation. The asset retirement liability will be allocated to operating expense by using a systematic and rational method. The Company has recorded a net liability of $289,631 as of March 31, 2007, compared to $129,205 as of March 31, 2006. The information below reconciles the value of the asset retirement obligation for the periods presented.
Recently Issued Accounting Pronouncements:
In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes. The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 did not have any impact on the Company’s consolidated financial position, results of operations or cash flows.
On February 15, 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities.” This Statement establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for the Company’s financial statements issued in 2008. The Company is currently evaluating the impact that the adoption of SFAS No. 159 might have on its financial position or results of operations.
Note 3 – Compensation Plan
Stock-based Compensation Plan
The Company has a stock-based compensation plan whereby share purchase options may be granted with an exercise price equal to the trading value when granted. The total number of share purchase options outstanding cannot exceed 10% of the total number of shares issued.
For the three-month periods ended March 31, 2007 and 2006, the Company recorded stock-based compensation of $275,580 and $51,243 respectively. The Company did not grant any options during these same periods.
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The following assumptions were used for the Black-Scholes model:
A summary of the stock options outstanding is as follows:
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At March 31, 2007, stock options outstanding are as follows:
Note 5 - Commitments and Contingencies
Rent expense was $21,555 and $16,324 for the periods ended March 31, 2007 and 2006 respectively. In February 2007, the Company entered into a lease agreement for office facilities that expires June 2012. This lease replaced the Company’s previous lease that was scheduled to expire on June 30, 2010.
The following table shows the annual rentals per year for the life of the lease committed to in February 2007:
The Company has no other capital leases and no other operating lease commitments.
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.
Note 6 – Differences Between Canadian and United States Accounting Principles
These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America which differ in certain respects with those principles and practices that the Company would have followed had its financial statements been prepared in accordance with accounting principles and practices generally accepted in Canada.
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The Company’s accounting principles generally accepted in the United States of American differ from accounting principles generally accepted in Canada as follows:
US GAAP requires disclosure of comprehensive loss which, for the Company, is net loss under US GAAP plus the change in cumulative translation adjustment under US GAAP.
Comprehensive loss came into effect with fiscal years beginning on or after October 1, 2006.
Management does not believe that any recently issued, not yet effective, Canadian accounting standards if currently adopted could have a material effect on the accompanying financial statements.
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Forward-Looking Statements
This Quarterly Report includes certain statements that may be deemed to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements included in this Quarterly Report, other than statements of historical facts, address matters that the Company reasonably expects, believes or anticipates will or may occur in the future. Forward-looking statements may relate to, among other things:
Other sections of the Quarterly Report may include additional factors that could adversely affect our business and financial performance. Moreover, we operate in a very competitive and rapidly changing environment. New risk factors emerge from time to time and it is not possible for our management to predict all risk factors, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. Our forward-looking statements contained in this Quarterly Report are made as of the respective dates set forth in this Quarterly Report. Such forward-looking statements are based on the beliefs, expectations and opinions of management as of the date the statements are made. We do not intend to update these forward-looking statements, except as otherwise required by law. For the reasons set forth above, investors should not place undue reliance on forward-looking statements.
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Overall Performance
The Company is a public company listed on the American Stock Exchange (AMEX), trading symbol “KOG”, and is engaged in the business of exploration and development of oil and gas properties. The Company’s principal focus is on the exploration and development of oil and gas properties within two producing basins in the Rocky Mountain Region. The Company is exploring and developing natural gas in the Green River Basin in southwestern Wyoming and oil in the Williston Basin in Montana and North Dakota.
Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. The commodity prices are beyond the company’s control and are difficult to predict. Spot market prices reflected worldwide concerns about producer ability to ensure sufficient supply to meet increasing demand amid a host of uncertainties caused by political instability, a weaker US dollar and crude oil refining constraint. We receive lower prices for our oil and gas than what is posted on the New York Mercantile Exchange (NYMEX). The price differentials received for our products vary from month to month.
Exploratory Activity
Williston Basin-Wrangler/Lowell Prospect
We own a 50% working interest (WI) and operate the Wrangler/Lowell Project located in Sheridan County, Montana encompassing approximately 22,194 gross acres. The primary producing objectives include the Mission Canyon and the Red River Formations at approximate depths of 8,000 feet and 11,000 feet, respectively. During the first quarter of 2007 we completed the Larsh #2-13 well in the Red River Formation. The well was placed on production with an initial flowing rate of 232 barrels of oil per day. The well is still flowing but will be placed on pump during the second quarter of 2007.
We have identified several geologic leads in this same prospect area based on a 3-D seismic program completed in 2006. We are currently drilling a stepout to the Larsh #2-13 well, which we expect to complete in May 2007. The Company’s share of the development well is expected to be $1.4 million through completion.
Williston Basin-Great Bear Prospect
The Great Bear Prospect is located along the northwest flank of the Williston Basin in Divide County, North Dakota. The main reservoir objective is porous dolomite in the Ordovician Red River Formation. The Red River Formation produces oil and natural gas from structural and stratigraphic traps in the area of interest. We have acquired an interest under approximately 14,500 gross acres on the Great Bear Prospect. Based upon a reinterpretation of seismic data, we have identified additional potential locations. We intend to drill one exploratory well on the prospect lands late in the second quarter of 2007. The Company’s share of the drilling and completion costs is estimated at $2.0 million.
Green River Basin--Vermillion Basin, Sweetwater County, Wyoming
Vermillion Basin Shallow - Almond Sandstone, Almond Coals and Ericson Sandstone
During the fourth quarter of 2006, the Company participated in a development program of three vertical wells (approximate depth of 6,000 feet) on its Chicken Springs Unit (50% WI 42% net revenue interest (NRI); non-operator) in Sweetwater County, Wyoming to develop natural gas from the Almond
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sands. The wells were completed during the first quarter of 2007 and placed in production at rates of 300-600 Mcfpd. We are currently enlarging our compression facilities in the area. We are not planning any additional development drilling in this area as these formations will be evaluated in the drilling of the deeper formations as discussed below.
Vermillion Basin Deep-Gas Project – Baxter Shale and Frontier and Dakota Sandstone Chicken Springs, Chicken Ranch, Whiskey Canyon, Horseshoe Basin Units
The primary over-pressured deeper natural gas targets of the Vermillion Basin area are the Baxter Shale and Frontier sands at depths of up to approximately 15,000 feet. The prospective zones are present over a very large geologic area and have undergone the proper burial and subsequent uplift to generate hydrocarbons in the dry gas phase and maintain the over-pressuring created during hydrocarbon generation. Based upon early exploration work, the current production drainage projections would require well spacing of a maximum of 40 acres. While the total prospective productive area is unknown at this time, we currently control 49,427 gross acres (30,892 net), giving us the potential for over 750 locations based upon a 40-acre spacing pattern. Currently these wells cost $5.0-$6 million per well for drilling and completion.
During the first quarter of 2007, the Company completed the NT Federal #1-33 well (100% WI, 84.5% NRI – Kodiak operated) to a depth of 14,331 feet. The well was placed on production in late February 2007. The North Trail-State #4-36 (100% WI – Kodiak operated), was drilled to a total depth of 14,625 feet in late 2006 and was put on production in May 2007. We experienced some mechanical issues during completion which delayed getting the well onto sales. We are currently drilling the NT Federal #4-35 well located between the two aforementioned wells. The well is drilling below 9,000 feet and drilling operations should be completed in late May 2007 followed by completion work. We intend to drill up to six additional wells through the balance of the year and into 2008 and have allocated approximately $35 million of our budget to this project area.
We are in the process of permitting and shooting an approximate 43 square mile 3-D seismic program over the northern block of our acreage. We anticipate that the permitting process will be completed in the second quarter of 2007, with the data acquisition and interpretation to be completed during the third quarter of 2007. Total costs of the seismic program will be approximately $1.5 million, which might be shared by other working interest owners in the area.
Product Prices and Production
Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. The commodity prices are beyond the company’s control and are difficult to predict. Oil and gas volume and price realization comparisons for the indicated periods are set forth below. The Company does not hedge any of its production.
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Exploration and Development Costs
The prices received for domestic production of oil and gas have risen over the past several years. While such prices are subject to significant fluctuation, the upward trend in commodity prices has increased the demand for oil field services and equipment. As a result, over the past several years, the Company has experienced increases in development costs, such as those pertaining to rig rates, field service costs and material prices, as well as costs associated with drilling, completing and operating wells.
Asset Impairment
As of March 31, 2007, the Company’s full cost pool exceeded the ceiling limitation based on oil and gas prices of $55.12 per barrel and $4.16 per Mcf (including British Thermal Unit “BTU” adjustments of $0.38 per Mcf). In contrast, our oil and gas prices as of December 31, 2006 were $50.37 per barrel and $4.53 per Mcf (including BTU adjustments of $0.45). Consequently, the Company recorded an impairment expense of $14,000,000 during the period ended March 31, 2007.
The impairment was caused primarily by lower prices for natural gas production in the Rocky Mountain region, which the Company believes resulted from pipeline capacity constraints. As of March 31, 2007, the Henry Hub pricing for natural gas was $7.34 per Mcf, resulting in a differential of $3.56 per Mcf. Until additional pipelines are completed (the Rockies Express Pipeline is scheduled for extension in 2008, with anticipated completion in 2009), we expect differentials in the Rocky Mountains to remain higher than in other areas of the United States. The lower prices were not offset by increases in our reported reserves. In the first quarter, the Company was unable to complete the North Trail State #4-36 and the NT Federal #1-33 in the Vermillion Basin, as originally planned.
Results of Operations
Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006
The Company reported a net loss for the three months ended March 31, 2007 of $14,454,833 compared with a net loss of $5,515 for the same period in 2006. $14,000,000 of the 2007 loss is attributable to our full cost pool write-down during this period, which derives from lower gas prices at quarter end as described above. The Company’s earnings before interest, taxes, depreciation, depletion, amortization, gain on foreign currency and stock based compensation (“Adjusted EBITDA”) increased to $762,372 for the three months ended March 31, 2007 compared to $485,777 for the same period ended March 31, 2006. Adjusted EBITDA is not a GAAP measure of performance. The company uses this non-GAAP performance measure primarily to compare its performance with other companies in the industry that make a similar disclosure. The Company believes that this performance measure may also be
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useful to investors for the same purpose. Investors should not consider this measure in isolation or as a substitute for operating income, or any other measure for determining the Company’s operating performance that is calculated in accordance with GAAP. In addition, because Adjusted EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies. Reconciliation between Adjusted EBITDA and net income is provided in the table below:
Gas production volumes were 45,915 and 32,047 Mcf for the three-month periods ended March 31, 2007 and 2006, respectively. Oil production volumes were 25,266 and 12,998 barrels for the three-month periods ended March 31, 2007 and 2006. As the oil and gas price and volume table above shows, total gas price realizations decreased 10.56% to $6.52 per Mcf for the three-month period ended March 31, 2007 compared to the same period ending March 31, 2006. Oil price realizations were $50.55 per barrel for the three-month period ended March 31, 2007 compared to $51.92 for the same period ending March 31, 2006. The net effect of the pricing and volume changes resulted in oil and gas revenues of $1,576,817 for the three-month period ended March 31, 2007 compared to $908,578 for the same period ending March 31, 2006. On a natural gas equivalent basis, the Company produced 197.5 MMcfe for the first quarter, using a conversion rate of 6 Mcf gas to each barrel of oil. This compares to 109.7 MMcfe for the same period in 2006.
The Company recorded lease operating and production tax expense of $390,775 during the three-month period ended March 31, 2007, as compared to $112,914 during the same period in 2006. Depreciation, depletion, amortization and abandonment liability accretion was $1,039,246 for the three-month period ended March 31, 2007 compared to $387,516 for the same period in 2006. The changes in these expenses reflect the Company’s growing production base, number of producing wells and revenues.
The Company’s general and administrative costs of $1,262,960 during the three months ended March 31, 2007 compares to $464,803 for the same period in 2006. Included in the general and administrative expense is a stock based compensation charge of $275,580 and $51,243 for the periods ending March 31, 2007 and 2006, respectively, for options issued to officers, directors and employees in compliance with Statement of Financial Accounting Standards (“SFAS”) No. 123, Accounting for Stock-Based Compensation. The increase in general and administrative expenses is a result of the Company’s increased staffing requirements and level of activity. The Company currently has twelve full-time employees and one part-time employee, an increase of six from the same period in 2006.
As of March 31, 2007, based on current oil and gas prices of $55.12 per barrel and $4.16 per Mcf for our gas in the Rocky Mountain Region, the present value of the Company’s future net revenue discounted at 10% exceeded the Company’s full cost pool. Therefore, impairment expense of $14,000,000 was recorded during the quarter ended March 31, 2007.
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Liquidity and Capital Resources
As of March 31, 2007, the Company had working capital of $42,000,204 and no long term debt. The Company believes that its current working capital and cash flow from operations will fund the Company’s anticipated exploration and development drilling program through year end and into the first part of 2008. During the three-month periods ended March 31, 2007 and 2006, the Company’s share of exploration and development costs was $13,341,387 and $14,420,938, respectively.
The Company is currently operating two rigs in the Rocky Mountain Region. The Company has secured a drilling rig for its deep Vermillion Basin prospect area. This drilling program has commenced and drilling activity should continue throughout 2007. The Company is operating a second rig in the Williston Basin. We anticipate utilizing this same rig throughout 2007. Future expenditures will be subject to the results of continued production. The Company anticipates capital expenditures of approximately $45 million over the remaining nine months of 2007. The capital expenditures budget includes the proposed drilling and completion of approximately 20 gross wells (13.38 net wells) for the total 2007 program. In the Greater Green River Basin, the budget allocates $31.5 million to seven gross and net (100% WI) wells targeting the Baxter Shale and Dakota and Frontier sands. Existing working capital, anticipated cash flow from operations and access to a reserve-based revolving line of credit, which we intend to establish during the year, are expected to be sufficient to fund the remaining 2007 operations and capital commitments.
As of March 31, 2007, the Company had no lines of credit or other bank financing arrangements. The Company is currently working towards developing a credit facility. The Company has no defined benefit plan and no obligation for post retirement employee benefits.
Financial Instruments and Other Instruments
As of March 31, 2007 the Company had cash, accounts payable and accrued liabilities, which are each carried at approximate fair value due to the short maturity date of those instruments. Unless otherwise noted, it is management’s opinion that the Company is not exposed to significant interest, currency or credit risks arising from these financial instruments.
Critical Accounting Policies and Estimates
We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2006.
Recently Issued Accounting Pronouncements:
In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes. The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 did not have a material impact on the Company’s consolidated financial position, results of operations or cash flows.
On February 15, 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities.” This Statement establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for
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similar types of assets and liabilities. SFAS No. 159 is effective for the Company’s financial statements issued in 2008. The Company is currently evaluating the impact that the adoption of SFAS No. 159 might have on its financial position or results of operations.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet financing arrangements at March 31, 2007.
Oil and Gas Price Fluctuations
Our primary market risk is market changes in oil and natural gas prices. Prospective revenues from the sale of products or properties will be impacted by oil and natural gas prices. A $1.00 per Mcf change in the market price of natural gas will result in approximately a $45,000 change in our gross gas production revenue. A $1.00 per barrel change in the market price of oil will result in approximately a $25,000 change in our gross oil production revenue. The impact on any potential sale of property cannot be readily determined.
Interest Rate Fluctuations
We currently maintain some of our available cash in redeemable short term investments, classified as cash equivalents, and our reported interest income from these short term investments could be adversely affected by any material changes in US dollar interest rates. A 1% change in the interest rate would have approximately a $420,300 annual impact if all of our cash was invested in interest bearing notes.
Under the supervision and with the participation of our management, we evaluated the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the “Exchange Act”) as of March 31, 2007. On the basis of this review, our management concluded that our disclosure controls and procedures are effectively designed to give reasonable assurance that the information we are required to disclose in reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer, in a manner that allows timely decisions regarding required disclosure.
There were no changes in the Company’s internal controls over financial reporting that occurred in the first fiscal quarter of 2007 that materially affected, or were reasonably likely to materially affect, its internal control over financial reporting.
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PART II — OTHER INFORMATION
Information about material risks related to the Company’s business, financial condition and results of operations for the three months ended March 31, 2007 does not materially differ from the information set forth under the heading “Risk Factors” in Part I, Item 1A in the Company’s Annual Report on Form 10-K for the year ended December 31, 2006. The risk factors disclosed in Part I, Item 1A to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006, in addition to the other information set forth in this quarterly report, could materially affect our business, financial condition or results of operations. Additional risks and uncertainties not currently known to us or that we deem to be immaterial could also materially adversely affect our business, financial condition or results of operations.
In December 2006, we raised net proceeds of $46,672,213 in a public offering of 12,075,000 shares of common stock, all of which shares were sold. The registration statements to register the shares became effective on December 15, 2006 (commission file number 333-138932) and December 18, 2006 (commission file number 333-139441). During the quarter ended March 31, 2007, we used approximately $13 million of net proceeds from the offering for exploration and drilling activities. We expect to use the remainder of our net proceeds to fund a portion of our 2007 exploration and drilling programs and for working capital and general corporate purposes.
None.
None
None.
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ITEM 6. EXHIBITS
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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.
KODIAK OIL & GAS CORP.
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