EXHIBIT 99.1
ADDITIONAL DISCLOSURES
Set forth below is the additional disclosure that the Company has agreed to provide in the notes accompanying the Company’s financial statements included in the Company’s future filings with the SEC.
Revisions to Note 2 to the Consolidated Financial Statements of Kodiak Oil & Gas Corp.
As reflected by the marked text set forth below, the second paragraph under the heading of “Oil and Gas Producing Activities” will be revised as follows:
Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs 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 the Company’s engineers and audited by independent petroleum engineers. included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment 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. During 2007, approximately $499,500 of unproved land costs related primarily to our North Dakota acreage were reclassified to proved property and were included in the ceiling test and depletion calculations. There were no reclassifications in 2006.
As reflected by the marked text set forth below, the third paragraph under the heading of “Oil and Gas Producing Activities” will be revised as follows:
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 costs 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 of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower of unproved properties that are subject to amortization. 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.
The last sentence in the sixth paragraph under the heading of “Oil and Gas Producing Activities” will be revised to read: “As the Company’s wells are produced over time and more data is available, the estimated proved reserves will be re-determined at least on an annual basis on a quarterly basis and may be adjusted based on that data.”
Revisions to Note 3 to the Consolidated Financial Statements of Kodiak Oil & Gas Corp.
The Company will add the following text under the table entitled “Unproved Additions by Year”:
During the year ended December 31, 2007, approximately $499,500 of unproved land costs related primarily to our North Dakota acreage was reclassified to proved property and was included in the ceiling test and depletion calculations.
We plan to make capital expenditures of approximately $12,600,000 for 2008. We have allocated $2,100,000 to our operations in the Vermillion Basin primarily related to geophysical studies and land leasing. This assumes no contribution to the costs of drilling up to three gross wells which will be paid for by Devon as part of the Devon Agreement. We have estimated that we will incur an additional $10,400,000 of capital expenditures in the exploration of the Bakken play in North Dakota and for workovers of existing Bakken wells to the west of our Dunn County acreage position. Depending on the timing of the receipt of permits from regulatory agencies, rig availability and the success of each well, we expect to drill three to four gross wells in this area in 2008. The unproved costs associated with the Company’s drilling projects will be transferred to proved properties as the wells are drilled over the next five to ten years.
Revisions to “Supplemental Oil and Gas Reserve Information (Unaudited)” Section in the Consolidated Financial Statements of Kodiak Oil & Gas Corp.
This disclosure will be expanded to add the following additional information at the end of this section:
As of December 31, 2007, we had estimated proved reserves of 2.7 billion cubic feet (“BCF”) of natural gas and 932 thousand barrels (“MBbls”) of oil with a present value discounted at 10% of $36.2 million. Our reserves are 75% proved developed and are comprised of 33% natural gas and 67% crude oil on an energy equivalent basis. Our December 31, 2007 natural gas reserves reflect a downward revision of the December 31, 2006 reserves of 1.1 BCF. Such downward revision of our reserves is primarily associated with the underperformance of one exploratory well in the Vermillion Basin.
Vermillion Basin: North Trail State #4-36 well. In December 2006, we had recently completed the North Trail State #4-36, and, based on early results, production from wells offsetting the lease, and geological studies, the North Trail State #4-36 was estimated to have 1.6 BCF of reserves. In 2007, due to various mechanical problems, including collapsed casing that made production from North Trail State #4-36 impossible from the deeper formations, production from North Trail State #4-36 did not meet anticipated flow rates. As a result, in the 2007 reserve study, only the reserves from the shallow formation on the North Trail State #4-36 were considered and no reserves from the deeper Baxter Formation were recorded. Because the North Trail State #4-36 constituted a large percentage of our total gas reserves, the adjustment to the reserves for North Trail State #4-36 dramatically impacted our total reserves.
