Kodiak Oil 10-Q 2008
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2008
Commission File No. 001-32920
(Exact name of registrant as specified in its charter)
1625 Broadway, Suite 250
Denver, Colorado 80202
(Address of principal executive offices, including zip code)
(Registrants 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.
Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definition of accelerated filer, large accelerated filer and smaller reporting company 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).
Yes o No x
88,030,431 shares of no par value of the Registrants Common Stock were issued and outstanding as of April 30, 2008.
KODIAK OIL & GAS CORP.
KODIAK OIL & GAS CORP.
SEE ACCOMPANYING NOTES
KODIAK OIL & GAS CORP.
SEE ACCOMPANYING NOTES
KODIAK OIL & GAS CORP.
SEE ACCOMPANYING NOTES
KODIAK OIL & GAS CORP.
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) and 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 condensed 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 Corporations business is transacted in US dollars and, accordingly, the financial statements are expressed in US dollars. The accompanying unaudited condensed 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 condensed consolidated financial statements contain all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation of the Companys results for the periods presented. These unaudited condensed consolidated financial statements should be read in conjunction with the Companys audited consolidated financial statements included in the Annual Report on Form 10-K for the fiscal year ended December 31, 2007. 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 2007 unaudited condensed consolidated financial statements have been reclassified to conform to the 2008 unaudited consolidated financial statement presentation; such reclassifications had no effect on the 2007 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.
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.
The restricted investment balance as of March 31, 2008, is comprised of: (a) $188,475 certificate of deposit to collateralize a surety bond to provide for state bonding requirements for plugging and abandonment liabilities; and (b) $69,797 certificate of deposit to collateralize the costs of office improvements that will be released over the four year remaining term of the lease at $17,450 per year.
Concentration of Credit Risk
The Companys 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 may at times have balances in excess of the federally insured limits.
The Companys 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, and 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.
Capitalized costs, 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 the Companys engineers and audited annually 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.
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 Companys overall value. These estimates are also used in the quarterly calculations of depletion, depreciation and impairment of the Companys 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 (the SEC), such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of 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 optimal 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. Most of the Companys wells have been producing for a period of less than six years and for some, less than a year. Because of this short production history, other generally less accurate methods such as volumetric analysis and analogy to the production history of wells of ours and other operators in the same reservoir were used in conjunction with the decline analysis method to determine the Companys estimates of proved reserves including developed producing, developed non-producing and undeveloped. As the Companys wells are produced over time and more data is available, the estimated proved reserves will be re-determined at least on an annual basis and may be adjusted based on that data.
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, 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.
Primarily as the result of the Companys inability to establish production and qualified reserves in its deep Vermillion Basin project, low natural gas prices in Wyoming, and the impairment of certain undeveloped properties in Wyoming and North Dakota, the Company recorded an impairment expense of $34.0 million in 2007 including $14.0 million in the first quarter of 2007.
Wells in Progress
Wells in progress at March 31, 2008 and December 31, 2007, represent the costs associated with the drilling of wells in Wyoming. Since the wells have not reached total depth or been completed as of period end they were classified as wells in progress and were withheld from the depletion calculation and the ceiling test. The costs for these wells will be transferred to proved property when the wells reach total depth and are cased and will become subject to depletion and the ceiling test calculation in future periods.
Impairment of Long-lived Assets
The Companys unproved properties are evaluated quarterly for the possibility of potential impairment. In the three months ended March 31, 2008, the Company did not recognize any impairment losses. As of March 31, 2007, the Companys 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.
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 Companys financial instruments, including cash and cash equivalents, accounts receivable and accounts payable, are carried at cost, which approximates fair value due to the short-term maturity of these instruments.
The Company records revenues from the sales of natural gas and crude oil when they are produced and sold. 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 Companys over and under produced gas balancing positions are considered in the Companys proved oil and gas revenues. Gas imbalances at March 31, 2008, and December 31, 2007 were not significant.
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 condensed 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, 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. As of March 31, 2008, and December 31, 2007, the Company has recorded a net asset of $608,838 and $660,986 and a related liability of $742,396 and $874,498, respectively. In December 2007, the Company revised its estimated dismantlement and abandonment costs based upon the actual costs of recently plugged and abandoned wells. The information below reconciles the value of the asset retirement obligation for the periods presented.
Recently Issued Accounting Pronouncements:
In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements. The statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. In February 2008, the FASB issued Staff Position No. FAS 157-2 which proposed a one year deferral for the implementation of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually).
On January 1, 2008 we elected to implement this Statement with the one-year deferral. The adoption of SFAS No. 157 did not have a material impact on our financial position, results of operations or cash flows. Beginning January 1, 2009, we will adopt the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis. We are in the process of evaluating this standard with respect to our effect on nonfinancial assets and liabilities and have not yet determined the impact that it will have on our financial statements upon full adoption in 2009.
SFAS No. 157 (as amended), defines fair value, establishes a framework for measuring fair value, outlines a fair value hierarchy based on inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties. A liabilitys fair value is defined as the amount that would be paid to transfer the liability to a new obligor, not the amount that would be paid to settle the liability with the creditor. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued.
Beginning January 1, 2008, assets and liabilities recorded at fair value in the consolidated balance sheets are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levelsdefined by SFAS 157 and directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilitiesare as follows:
· Level IInputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.
· Level IIInputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instruments anticipated life.
· Level IIIInputs reflect managements best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.
Our asset retirement obligation is measured using primarily Level III inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging and abandonment costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities-Including an Amendment of FASB Statement No. 115 (FAS 159). This Statement allows an entity the option to elect fair value for the initial and subsequent measurement for certain financial instruments and other items that are not currently required to be measured at fair value. If a company chooses to record eligible items at fair value, the company must report unrealized gains and losses on those items in earnings at each subsequent reporting date. FAS 159 also prescribes presentation and disclosure requirements for assets and liabilities that are measured at fair value pursuant to this standard. FAS 159 was effective for the Company as of January 1, 2008. The adoption of FAS 159 did not have a material impact on the Companys financial position or results of operations.
In December 2007, the FASB issued SFAS No. 141-R, Business Combinations (FAS 141R) which revised SFAS No. 141, Business Combinations (FAS 141). This pronouncement is effective for the Companys financial statements issued after January 1, 2009. Under FAS 141, organizations utilized the announcement date as the measurement date for the purchase price of the acquired entity. FAS 141R requires measurement at the date the acquirer obtains control of the acquiree, generally referred to as the acquisition date. FAS 141R will have a significant impact on the accounting for transaction costs, restructuring costs as well as the initial recognition of contingent assets and liabilities assumed during a business combination. Under FAS 141R, adjustments to the acquired entitys deferred tax assets and uncertain tax position balances occurring outside the measurement period are recorded as a component of the income tax expense, rather than goodwill. As the provisions of FAS 141R are applied prospectively, the impact to the Company cannot be determined until the transactions occur. interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. The Company does not expect that the adoption of FAS 160 will have a material effect on its financial position or results of operations.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (FAS 160). This Statement establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. FAS 160 is effective for fiscal years, and
interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. The Company does not expect that the adoption of FAS 160 will have a material effect on its financial position or results of operations.
Note 3 Wells in Progress
The following table reflects the net changes in capitalized additions to wells in progress during the three months ended March 31, 2008, and the year ended December 31, 2007, and does not include amounts that were capitalized and reclassified to producing wells in the same period.
Note 4 Stock-based Compensation Plan
In 2007 the Company adopted the 2007 Stock Incentive Plan (the 2007 Plan), which replaced the Incentive Share Option Plan (the Pre-existing Plan). The 2007 Plan authorizes the Company to issue stock options, stock appreciation rights (SARs), restricted stock and restricted stock units, performance awards, stock or property, stock awards and other stock-based awards may be granted to any employee, consultant, independent contractor, director or officer of the Company. A total of 8,000,000 shares of common stock may be issued under the 2007 Plan, which includes shares issuable under the Pre-existing Plan pursuant to options outstanding as of the effective date of the 2007 Plan. No more than 8,000,000 shares may be used for stock issued pursuant to incentive stock options and the number of shares available for granting restricted stock and restricted stock units shall not exceed 1,000,000, subject to adjustment as defined in the 2007 Plan. The Company granted 965,000 stock options in the three-month period ended March 31, 2008.
Compensation expense charged against income for all stock-based awards during the three months ended March 31, 2008, and March 31, 2007, was $1,518,810 and $275,580, respectively. This increase is primarily due to additional stock-based awards granted since March 31, 2007, as well as the true up of the cumulative expense as a result of comparing the assumed forfeiture rate to actual forfeitures.
The following assumptions were used for the Black-Scholes model to calculate the stock-based compensation expense for the periods presented:
A summary of the stock options outstanding as of March 31, 2008, is as follows:
At March 31, 2008, stock options outstanding are as follows:
The aggregate intrinsic value of both outstanding and vested options as of March 31, 2008, was $1,996,510, based on the Companys March 31, 2008, closing common stock price of $1.67. This amount would have been received by the option holders had all option holders exercised their options as of that date. The total grant date fair value of the shares vested during the three months ended March 31, 2008 was $414,600. As of March 31, 2008, there was $5,201,895 of total unrecognized compensation cost related to unamortized options. That cost is expected to be recognized over a period of approximately three years.
As of March 31, 2008, there were 61,000 unvested shares of restricted stock grants with a weighted-average grant date fair value of $4.91 per share. Total unrecognized compensation cost of $206,657 related to non-vested restricted stock is expected to be recognized over a three-year period. The Company recognizes compensation cost over the requisite service period for the entire award. The fair value of restricted stock grants is based on the stock price on the grant date and the Company assumes no annual forfeiture rate.
Note 5 - Commitments and Contingencies
The Company leases office facilities under an operating lease agreement that expires on June 30, 2012. Rent expense was $78,737 and $21,555 for the three month periods ended March 31, 2008 and 2007, respectively.
The following table shows the remaining annual rentals per year for the life of the lease:
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. Management does not believe the financial statements would vary materially had they been prepared in accordance with Canadian GAAP or that any recently issued, not yet effective, Canadian accounting standards if currently adopted could have a material effect on the accompanying financial 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:
· the Companys future financial position, including working capital and anticipated cash flow;
· the risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas;
· market demand;
· risks and uncertainties involving geology of oil and gas deposits;
· the uncertainty of reserve estimates and reserves life;
· the uncertainty of estimates and projections relating to production, costs and expenses;
· potential delays or changes in plans with respect to exploration or development projects or capital expenditures;
· fluctuations in oil and gas prices, foreign currency exchange rates and interest rates;
· health, safety and environmental risks;
· uncertainties as to the availability and cost of financing; and
· the possibility that government policies or laws may change or governmental approvals may be delayed or withheld.
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.
Kodiak Oil & Gas Corp. is an independent energy company focused on the exploration, exploitation, acquisition and production of natural gas and crude oil in the United States. Our oil and natural gas reserves and operations are primarily concentrated in two Rocky Mountain basins the Green River Basin of Wyoming and Colorado and the Williston Basin of North Dakota and Montana. Kodiaks corporate strategy is to internally identify prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as conventional and unconventional prospects, that we have the opportunity to explore, drill and develop.
First Quarter 2008 Highlights
Kodiaks results of operations and financial condition are significantly affected by the success of our exploration and land leasing activity, the resulting production and reserves, oil and natural gas commodity prices, and the costs related to operating our properties. In the first quarter of 2008, our oil and gas revenue increased by 16% from the first quarter of 2007. This increase is largely the result of higher realized prices received for both our crude oil and natural gas production offset by a decrease in our crude oil production. The decrease in our crude oil production was a result of oil producing wells that were shut in for repair and workover procedures. Total costs and expenses decreased to $4.6 million in the first quarter of 2008 from $16.6 million in the first quarter of 2007 largely due to an asset impairment in 2007 of $14.0 million related to the full cost ceiling test. Costs and expenses in the first quarter of 2007 were impacted by higher oil and gas production costs and general and administrative expenses. Included in the oil and gas production costs for the first quarter of 2007 was approximately $467,000 of expenses related to repair work on a producing well. The increase in general and administrative expenses included an increase in the non-cash charge for stock based compensation of $1.2 million. This increase is due to additional options and restricted stock issued since March 31, 2007, and a change in the forfeiture rate assumed for future vested options.
In the first quarter of 2008, we have continued to add to our acreage position in the Bakken play on the Fort Berthold Indian Reservation through continual leasing negotiations and final approval from the Bureau of Indian Affairs. We believe that we have made significant progress in procuring the necessary permit to drill our first well on the Reservation. While this process took longer than expected, the absence of established protocols meant that we and the applicable agencies were required to work cooperatively to establish procedures for the industry and regulatory agencies to follow as oil and gas development progresses. Additionally, we have continued to evaluate our exploration activities related to our prospective land positions by interpreting additional geological and geophysical data in both the Williston Basin and Vermillion Basin properties. We expect that completed 3-D seismic studies, acquired in both Basins in 2007, will prove useful well into the future as we seek to expand our production base through additional drilling.
In January 2008, we entered into the Devon Agreement with Devon Energy Production Company, L.P., a wholly owned subsidiary of Devon Energy Corp (Devon) under which Devon earned an interest in our leasehold interests in the Vermillion Basin in exchange for, among other things, drilling up to three wells at Devons sole cost and risk by November 15, 2009.
As part of the Devon Agreement, we and Devon have set forth terms and conditions that create an Area of Mutual Interest (AMI) for the exploration, leasing, and development of certain of our Vermillion Basin properties. Upon completion of each of the three wells, we will have a 50% working interest in each well, proportionately reduced in the event of third-party interest. By drilling the three wells, Devon will earn, among other considerations, 50% of our leasehold interest to all depths within the AMI, excluding any leasehold already jointly held by and between us and Devon and any existing Kodiak wellbores. Through reimbursement of costs totaling approximately $1.2 million, Devon also earned ownership in two existing wells, the Horseshoe Basin 5-3 and Whiskey Canyon Unit #3, so that Devon will own the same interest as Kodiak in these wells. Under the terms of the agreement, Devon will serve as operator but both parties will collaborate by each providing technical input and drilling and completion expertise in order to best develop the AMI properties. With this agreement, we believe that development will continue to move ahead in this play and our capital requirements will be limited in the short-term.
Kodiak ended the first quarter of 2008 with cash and cash equivalents of $9.9 million down from $13.0 million at year-end 2007. Total working capital was also $9.9 million at March 31, 2008, as compared to $10.2 million at December 31, 2007. Cash flow used in operating activities for the first quarter of 2008 was $2.4 million which was largely the result of a $2.7 million reduction in current assets and liabilities. Cash used as capital expenditures for our oil and gas activities totalled $3.1 million for the first quarter of 2008 and was offset by $2.4 million in proceeds from sales of oil and gas properties. Our estimated capital expenditures for the remainder of 2008 of $12.4 million is expected to be funded by existing working capital and other sources of capital including debt or equity financings or by entering into additional joint venture agreements. We can give no assurance that these financing sources will be available under acceptable terms or at all.
Liquidity and Capital Resources
Due to our active oil and natural gas exploration program, we have experienced, and expect to continue to experience, substantial working capital requirements. As a result of the Devon Agreement, we expect to maintain a high level of activity in the Vermillion Basin, without the need for Kodiak to undertake significant capital expenditures in the short-term. Based on our current exploration program and depending on the success in this play, we anticipate additional capital requirements by late 2008 and into 2009. By reducing the immediate capital requirements of the continuing Vermillion Basin exploration, we intend to allocate our existing capital to the Bakken play on the Fort Berthold Indian Reservation in North Dakota. Through an exploration agreement with a joint venture partner in this play, we have limited our initial capital exposure to an approximate 50% working interest in each of the early wells. On other acreage in the same play, we have a higher working interest and may seek to reduce this ownership through further joint ventures which would provide additional capital and reduce Kodiaks total requirements.
In the first quarter of 2008, we incurred capital expenditures of approximately $176,000, net of proceeds from property divestitures and the Devon transaction and including accruals. As of March 31, 2008, our working capital is $9.9 million and we continue to have no long-term debt. Our capital expenditure budget for 2008 is unchanged at a total of $12.6 million which is also net of proceeds from limited divestitures and joint venture arrangements that have occurred or are planned. In addition to this $12.6 million budget, we have other prospects that are in the early stages of exploration. Further spending on these prospects is contingent on the success of
the currently budgeted expenditures. As our anticipated funds from operations are expected to provide only a limited amount of additional working capital, we believe that it is likely that we will need to obtain additional sources of capital to fund further growth and development, the amount and timing of which will depend on the success and timing of our exploration activities. We anticipate that we would seek to obtain additional funding either by means of debt or equity financings or by entering into additional joint venture agreements, the availability of which there can be no assurance.
Our ability to fund our operations in future periods will depend upon our future operating performance, and more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. We cannot be certain that additional funding will be available on acceptable terms, or at all. If we are unable to raise additional capital when required or on acceptable terms, we may have to significantly delay, scale back or discontinue our drilling or exploration program, seek to enter into additional joint venture arrangements with third parties, or seek to sell one or more of our properties.
Oil and Gas Properties
As of March 31, 2008, we had several hundred lease agreements representing approximately 148,481 gross and 91,306 net acres primarily in the Green River and Williston Basins.
As of March 31, 2008, we had acquired 38,686 gross acres and 28,957 net acres in the Bakken oil play in Dunn County, North Dakota. An additional estimated 8,800 net acres have been leased and are in the approval process with the Bureau of Indian Affairs (BIA). We cannot be assured that we will receive title to these lands until final approval is received. The majority of our lands in this prospect area are administered by the BIA on behalf of the individual members of the Three Affiliated Tribes Fort Berthold Indian Reservation. Typically these lands are acquired through a private negotiation with the individual land owners or the Three Affiliated Tribes and have a primary lease term of five years. The land owner typically retains an 18% landowner royalty. In most cases, these lands require an annual delay rental of $2.50 per net acre.
As a result of the Devon Agreement, our leasehold interests in the Vermillion Basin total approximately 39,093 gross (14,421 net) acres. The AMI with Devon will expire after a period of five years, unless extended by mutual agreement of both parties. Each party has agreed to a proportionate share of any interest or lease acquired within the participating area.
In January 2008, we completed the sale of 4,784 gross and net acres in an exploratory Mancos Shale gas prospect located in the Sand Wash Basin in Moffat County, Colorado for $1.2 million. We retained a 5% overriding royalty in these properties as well as 100% working interest ownership in the remaining 3,770 acres. We believe the remaining acreage is prospective for production from the Mancos Shale and Niobrara Formation at a shallower depth than that divested.
The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases as of March 31, 2008.
(1) Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage includes proved reserves.
(2) Developed acreage is the number of acres that are allocated or assignable to producing wells or wells capable of production.
(3) Excludes 10,261 gross (6,127 net) acres that can be earned pursuant to existing farm-in agreements.
Operations in the Williston Basin of Montana and North Dakota
Bakken FormationMcKenzie and Dunn Counties, North Dakota
We have continued our ongoing acreage acquisition program in Dunn County, North Dakota where the primary objective is the dolomitic, sandy interval layered between the two Bakken Shales at an approximate vertical depth of 10,000 feet. This acreage is in a trend bordered by producing wells drilled by, among others, EOG Resources, Inc. and Whiting Petroleum Corp. to the north and Marathon Oil Corp. and ConocoPhillips to the west and south.
Subject to obtaining a permit to drill from the Bureau of Land Management (BLM) and the BIA and obtaining a drilling rig and equipment, drilling activity should commence in the second quarter of 2008. On April 7, 2008, we received a Finding of No Significant Impact (FONSI) and the necessary approval of the environmental assessment (EA) with respect to the Tall Bear #16-15H well on this prospect. Upon FONSI approval, the EA is subject to a 30 day comment period that will expire in early May 2008, at which time we would expect both final BIA and BLM approval. The EA approval is a key step in the drilling permit process and, while this permit is being processed, Kodiak is preparing to submit additional drilling permits for other wellsites. The Tall Bear #16-15H is a horizontal well targeting oil potential in the Bakken shale and is being permitted to a proposed total depth of 15,600 feet. We will operate and currently own an approximate 70% working interest in the proposed drill site and acreage block, but we may seek to reduce our working interest to approximate 50%.
In early April 2008, we also entered into a long-term contract for a new-build rig from a large land-drilling contractor. The rig is designed to our specifications to optimally drill horizontal Bakken shale wells and other Williston Basin formations. We expect the rig to be delivered in the third quarter of 2008 and it will be used exclusively for our Williston Basin operations, including Red River and Mission Canyon prospects. In order to expedite our Bakken drilling operations on the Tall Bear #16-15H well, we are actively seeking a one-well window for a sub-contracted rig from a drilling contractor or operator in the area.
In the first quarter of 2008, we began workover operations on our producing Bakken oil wells in McKenzie County near the North Dakota and Montana state line. In this play, we intend to clean out and fracture stimulate one well and re-fracture stimulate two wells. As part of this program, in the first quarter of 2008, we performed required repair work on the casing of one well in preparation of the workover operations. This work to repair the casing was completed and the well is capable of producing pending the workover. The net cost of approximately $467,000 related to the repair work was charged to oil and gas production costs and expenses in the first quarter of 2008.
Red River-Mission Canyon Play Sheridan County, Montana and Divide County, North Dakota
The primary producing objectives in this prospect area are the Mission Canyon and the Red River formations at approximate depths of 8,000 feet and 11,000 feet, respectively. We have recently completed interpreting an approximate 18 square mile 3-D seismic program over a portion of this acreage. The Company has identified two prospects within its acreage that it intends to drill during 2008. The Company has identified seismic leads on other blocks of its acreage that we expect to drill during 2008.
Operations in the Green River Basin of Wyoming and Colorado
Vermillion Basin Deep Baxter Shale and Frontier and Dakota Sandstone
Our primary leaseholdings in the Green River Basin are located in an area referred to as the Vermillion Basin. In this geologic region, we believe there is natural gas trapped in various sands, coals and shales at depths ranging from 2,000 feet to nearly 15,000 feet. The primary target of our current exploration efforts in this area is the over-pressured Baxter Shale at depths to approximately 13,000 feet.
In late 2007, we completed drilling operations on the Horseshoe Basin #5-3 well (50% WI, 42% NRI, operated by Devon) located on the western edge of the prospective producing area. This well was drilled vertically to a depth of 13,534 feet to evaluate the potential of the Almond and Ericson formations, the Baxter Shale and the Frontier Formation. The well was a significant step out and it is approximately 6 miles from the closest producing well. Following fracture stimulation of the Baxter shale in November, the initial twenty-four hour flowback rate was estimated at 3.0 million cubic feet (MMcf) of natural gas on a 16/64 choke and 3,500 psia of flowing casing pressure. Subsequently, the well was tested for 48 hours through a test separator and stabilized at approximately 2.0 MMcf per day with 350 barrels of condensate per
day. The well is currently waiting on the completion of a gathering pipeline which is expected to be in place by mid-summer 2008. Although Kodiak drilled and completed this well, as part of the Devon Agreement, Devon earned an increased ownership in this well and now operates the well.
Our 2008 exploration efforts in the Vermillion Basin prospect area will largely be driven by Devon. It is currently expected that the first drilling activities will be conducted on the western portion of our acreage in the Horseshoe Basin Unit in an effort to extend the reservoir as found in of the Horseshoe Basin #5-3 well. Drilling is anticipated to commence in the second quarter 2008 and continue into the fall months as lease stipulations expire and the locations are accessible. While drilling plans are still being finalized, we anticipate the first well will be a vertical well to evaluate only the Baxter Shale. The wells will be engineered to allow re-entry for horizontal drilling applications at a later date, if desired. Concurrently with the drilling activity we anticipate the acquisition of 3-D seismic covering the Horseshoe Basin Unit to help facilitate a development program in 2009 and beyond. We have completed the processing and interpretation of approximately 43 square miles of 3-D seismic on the northern block of our acreage which includes portions of our Chicken Springs and Chicken Ranch Federal Units, as well as land currently not included in federal units. While no specific drilling locations have yet been determined, we anticipate that additional wells will be drilled under the Devon Agreement in this area as a result of the seismic evaluation.
Production, Average Sales Prices, and Production Costs
Kodiaks 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 our control and are difficult to predict. Market prices reflect worldwide concerns about producer ability to ensure sufficient supply to meet increasing demand amid a host of uncertainties caused by political instability, a weaker U.S. 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 and the Company does not currently have hedges of its commodity sales in place.
The Companys oil and gas sales volumes are a direct result of the success of its exploratory and acquisition activities. Production volumes may vary monthly as various wells are completed or maintained to provide optimal flows.
Sales volumes, prices received, and production costs are summarized in the following table for the three-month periods ending March 31, 2008, and March 31, 2007. In the first quarter of 2008, we began preparations to perform workovers on our producing Bakken oil wells in McKenzie County, North Dakota. Although this work is expected to improve the production capabilities and increase their recoverable reserves, while the project is in progress, the wells production will be negatively impacted. As part of this preparation work, we performed repairs on the casing of one well and that well and another were shut in intermittently during the first quarter of 2008. As a result, our oil production for the quarter decreased significantly and the expenses that were incurred for repair work increased operating expenses by approximately $467,000. The sales volume and production cost metrics shown below reflect the effect of the reduced production and increased expenses.
We anticipate net capital expenditures of $12.6 million in 2008. The following tables set forth our capital expenditures for the three months ended March 31, 2008, and our planned capital expenditures for our principal properties in 2008. Net capital expenditures include both cash and accrued expenditures and are net of proceeds from divestitures. The 2008 estimated expenditures do not include the costs to drill additional wells that will help further evaluate our properties in the Vermillion Basin. These wells are to be drilled at the sole cost of Devon under the Devon Agreement.
(1) Net Capital Expenditures include accruals and are net of proceeds from divestitures.
Results of Operations
Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007
The Company reported a net loss for the three months ended March 31, 2008, of $2,632,036 compared with a net loss of $14,454,833 for the same period in 2007. Included in the net loss for the quarter ended March 31, 2007 is a $14,000,000 loss attributable to our full cost pool write-down during this period. The Companys net loss for the three months ended March 31, 2008, was impacted by the reduced crude oil production and increased operating expenses as a result of workover and repair procedures on its producing Bakken oil wells in McKenzie County, North Dakota.
In evaluating its business, Kodiak considers earnings before interest, taxes, depreciation, depletion, amortization, gain on foreign currency and stock-based compensation (Adjusted EBITDA) as a key indicator of financial operating performance and as a measure of the ability to generate cash for operational activities and future capital expenditures. The Companys Adjusted EBITDA decreased 99% to $2,354 for the three months ended March 31, 2008 from the same period in 2007. The decrease in Adjusted EBITDA was largely the result of decreased oil production as a result of workover preparation and repair work on producing wells. The repair costs increased operating expenses in the first quarter of 2008 and reduced Adjusted EBITDA by approximately $467,000. Adjusted EBITDA is not a Generally Accepted Accounting Principle (GAAP) measure of performance. The Company uses this non-GAAP measure primarily to compare its performance with other companies in the industry that make a similar disclosure and as a measure of its current liquidity. The Company believes that this measure may also be useful to investors for the same purpose and for an indication of the Companys ability to generate cash flow at a level that can sustain or support our operations and capital investment program. Investors should not consider this measure in isolation or as a substitute for operating income or loss, cash flow from operations determined under GAAP, or any other measure for determining
the Companys operating performance that is calculated in accordance with GAAP. In addition, because EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies. Reconciliation between EBITDA and net income for the three months ended March 31, 2008 and 2007, is provided in the table below:
Natural gas production volumes increased 45% and oil production volumes decreased 37% for the three month periods ended March 31, 2008, compared to the same period in 2007. Natural gas production increased as new wells were placed on production in 2007. Oil production decreased due to workover operations on producing wells which is expected to improve flow rates and extend the lives of the wells. Total gas price realizations increased 7.2% to $6.99 per Mcf for the three month period ended March 31, 2008, compared to the same period in 2007. Oil price realizations were $89.12 per barrel for the three month period ended March 31, 2007, compared to $50.55 for the same period in 2007. The net effect of the pricing and volume changes resulted in an increase of oil and gas revenues of $301,354 to $1,878,171 for the three month periods ended March 31, 2008, compared to the same period in 2007.
The Company recorded lease operating and production tax expense of $982,951 during the three month period ended March 31, 2008, as compared to $390,775 during the same period in 2007. In the first quarter of 2008, we began workover operations on our producing Bakken oil wells in McKenzie County near the North Dakota and Montana state line. In this play, we intend to clean out and fracture stimulate one well and re-fracture stimulate two wells. As part of this program, in the first quarter of 2008, we performed required repair work on the casing of one well in preparation of the workover operations. This work to repair the casing was completed and the well is back on production pending the workover. The net cost of approximately $467,000 related to the repair work was charged to oil and gas production costs and expenses in the first quarter of 2008.
Depreciation, depletion, amortization and abandonment liability accretion, or DD&A, was $1,097,299 for the three month period ended March 31, 2008, compared to $1,039,246 for the same period in 2007. DD&A expense increased during the quarter due to the reclassification of wells whose costs were previously classified as wells in progress thus increasing the amortization pool and the DD&A rate. This increase was partially offset by the reduced crude oil volume produced due to the workover operations on producing oil wells.
The Companys general and administrative costs of $2,495,042 during the three months ended March 31, 2008, compares to $1,262,960 for the same period in 2007. Included in the general and administrative expense for this period is a stock-based compensation charge of $1,518,810 and $275,580 for 2008 and 2007, respectively, for options and restricted stock issued
to officers, directors and employees. This increase is the result of options and restricted stock granted subsequent to March 31, 2007, and the true-up of stock-based compensation expense for the difference between actual forfeitures and assumed forfeitures when the awards were granted. The overall increase in general and administrative expenses is a result of the Companys increased staffing requirements and level of activity. The Company currently has seventeen full time and three contract employees compared to twelve full time and one part time employee in March 2007.
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, 2007.
Recently Issued Accounting Pronouncements
In December 2007, the FASB issued SFAS No. 141-R, Business Combinations (FAS 141R) which revised SFAS No. 141, Business Combinations (FAS 141). This pronouncement is effective for the Companys financial statements issued after January 1, 2009. Under FAS 141, organizations utilized the announcement date as the measurement date for the purchase price of the acquired entity. FAS 141R requires measurement at the date the acquirer obtains control of the acquiree, generally referred to as the acquisition date. FAS 141R will have a significant impact on the accounting for transaction costs, restructuring costs as well as the initial recognition of contingent assets and liabilities assumed during a business combination. Under FAS 141R, adjustments to the acquired entitys deferred tax assets and uncertain tax position balances occurring outside the measurement period are recorded as a component of the income tax expense, rather than goodwill. As the provisions of FAS 141R are applied prospectively, the impact to the Company cannot be determined until the transactions occur.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51 (FAS 160). This Statement establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. FAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. The Company does not expect that the adoption of FAS 160 will have a material effect 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, 2008 other than lease committments as disclosed elsewhere in this 10-Q.
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 $66,600 change in our gross gas production revenue. A $1.00 per barrel change in the market price of oil will result in approximately a $15,900 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 $101,744 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, 2008. 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 Companys internal controls over financial reporting that occurred in the first fiscal quarter of 2008 that materially affected, or were reasonably likely to materially affect, its internal control over financial reporting.
Information about material risks related to the Companys business, financial condition and results of operations for the three months ended March 31, 2008 does not materially differ from the information set forth under the heading Risk Factors in Part I, Item 1A in the Companys Annual Report on Form 10-K for the year ended December 31, 2007. The risk factors disclosed in Part I, Item 1A to our Annual Report on Form 10-K for the fiscal year ended December 31, 2007, 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.
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.