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KOG > SEC Filings for KOG > Form 10-Q on 2-May-2013All Recent SEC Filings

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Quarterly Report

Forward-Looking Statements
The information discussed in this quarterly report on Form 10-Q includes "forward?looking statements" within the meaning of Section 27A of the Securities Act of 1933 (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward?looking statements. These forward?looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could," and similar terms and phrases. Although we believe that the expectations reflected in these forward?looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward?looking statements as a result of certain factors, including, among others:
         capital requirements and uncertainty of obtaining additional funding on
          terms acceptable to us;

         unsuccessful drilling and completion activities and the possibility of
          resulting write?downs;

         price volatility of oil and natural gas prices, and the effect that
          lower prices may have on our net income and stockholders' equity;

         a decline in oil or natural gas production, and the impact of general
          economic conditions on the demand for oil and natural gas and the
          availability of capital;

geographical concentration of our operations;

         constraints on us as a result of our substantial indebtedness,
          including restrictions imposed on us under the terms of our credit
          facility agreement and Senior Notes (defined below), and our ability to
          generate sufficient cash flows to repay our debt obligations;

         our ability to meet our proposed drilling schedule and to successfully
          drill wells that produce oil or natural gas in commercially viable

         financial losses and reduced earnings related to our commodity
          derivative agreements, and failure to produce enough oil to satisfy our
          commodity derivative agreements;

our history of losses;

         adverse variations from estimates of reserves, production, production
          prices and expenditure requirements, and our inability to replace our
          reserves through exploration and development activities;

         incorrect estimates associated with properties we acquire relating to
          estimated proved reserves, the presence or recoverability of estimated
          oil and natural gas reserves and the actual future production rates and
          associated costs of such acquired properties;

         hazardous, risky drilling operations and adverse weather and
          environmental conditions;

limited control over non-operated properties;

reliance on limited number of customers;

title defects to our properties and inability to retain our leases;

our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage;

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         our ability to retain key members of our senior management and key
          technical employees;

         constraints in the Williston Basin with respect to gathering,
          transportation and processing facilities and marketing;

federal, state and tribal regulations and laws;

         risks relating to managing our growth, particularly in connection with
          the integration of significant acquisitions;

         impact of environmental, health and safety, and other governmental
          regulations, and of current or pending legislation;

developments in the global economy;

changes in tax laws;

effects of competition;

effect of seasonal factors;

         lack of availability of drilling rigs, equipment, supplies, insurance,
          personnel and oil field services; and

         further sales or issuances of common stock and price volatility of our
          common stock.

Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in the section entitled "Risk Factors" included in our Annual Report on Form 10-K. All forward?looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this report. Other than as required under securities laws, we do not assume a duty to update these forward?looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise. Overview

We are an independent energy company focused on the exploration, exploitation, acquisition and production of crude oil and natural gas in the Rocky Mountain region of the United States. Historically, our corporate strategy has been 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 accumulated an unconventional oil and natural gas portfolio of proved reserves, which we are currently developing.

Our oil and natural gas reserves and operations are primarily concentrated in the Williston Basin of North Dakota, where the principal target of drilling is the Bakken Shale hydrocarbon system highlighted by production from the Middle Bakken member, located between two Bakken shales that serve as the source rock, and the Three Forks Formation, positioned immediately below the Lower Bakken Shale. As of March 31, 2013, we owned an interest in approximately 218,000 gross (154,000 net) acres in the Williston Basin and have an interest in 307 gross (139.3 net) producing wells in the Williston Basin.

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Recent Developments

Operational Update

We are currently operating seven drilling rigs and have experienced increased efficiencies, resulting in a corresponding increase in the number of wells drilled. In particular, we have reduced spud to completion days (including running and cementing the liner) from an average of 30 days in the early part of 2012 to a current average of 20 days. Drilling costs continue to decline from these decreased drilling times, as well as from cost reductions across the full spectrum of oil field goods and services. As we exited the first quarter of 2013, all of our rigs were drilling on three and four well pads, where we expect to see additional efficiency gains.

From late 2012 through February 2013, we operated with two full-time 24-hour-per-day completion crews. Beginning in March 2013, we reduced completion activities in anticipation of winter conditions and spring breakup. Our first quarter completions were also hindered with inefficiencies related to the completion of six single well pads. As drilling of our multi-well pads was completed in late first quarter, we intend to re-engage our second full-time 24-hour-per-day completion crew beginning in May 2013. With the additional completion crew scheduled in May and the multi-well pads waiting on completion, we expect to accelerate the pace of completions in the second quarter of 2013.

Our pilot programs to test 12 wells within a 1,280-acre drilling spacing unit (DSU) continue on schedule in the Polar and Smokey operating areas, with two drilling rigs operating in each area. Completion work in the Polar area, including a micro seismic program, is scheduled to commence in the second quarter of 2013. Completion work in the Smokey area will be ongoing throughout the year.

Given our current pace of drilling, we anticipate that our drilling and well completion efforts will exceed our previously announced 2013 well count of 75 gross (61.0 net) operated wells for the year. The additional wells are the result of operating a seventh rig longer than initially anticipated and gains in drilling efficiencies. We will monitor our progress through the second quarter and adjust our plans accordingly based on crude oil pricing and service costs. We have a staggered rig termination schedule with multiple rigs terminating in 2013, allowing us to adjust our rig count to align with our cash flow and capital expenditure projections.

We also continue to participate as non-operator in the drilling and completion of wells within the area of mutual interest ("AMI") area in Dunn County, North Dakota where two rigs are currently drilling, as well as other non-operated wells outside of the AMI. The following table summarizes the wells spud and completed during the three months ended March 31, 2013:

                             For the Three Months Ended March 31, 2013
                                       Spud                        Completed
                                   Gross                  Net    Gross     Net
Operated wells           21                              17.0     20      14.6
Non-operated wells       22                               3.4     20       4.1
                         43                              20.4     40      18.7

In an effort to reduce our lease operating expense, we drilled and equipped three additional water disposal wells during the quarter. We anticipate that oil, gas and water gathering lines in the Polar area should be substantially completed during the second quarter of 2013, which would then complete the significant portion of the pipeline work throughout our acreage blocks.

Financial Update

During April 2013, we completed the semi-annual borrowing base redetermination of our revolving credit facility. As a result, we entered into an amendment with our lenders, which increased our borrowing base to $650.0 million from the previous $450.0 million. At the present time, we elected to limit the aggregate commitment on the revolver to $550.0 million. Concurrently, the overall credit facility was increased from $750.0 million to $1.5 billion with the maturities extended to April 2018.

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Liquidity and Capital Resources
2013 Capital Expenditures Budget

Our 2013 capital expenditures budget is subject to various factors, including
market conditions, oil field services and equipment availability, commodity
prices and drilling results. The following table summarizes our 2013 capital
expenditures budget and our actual capital expenditures, including accruals, for
the three months ended March 31, 2013:
                                                               Three Months Ended
                                                                 March 31, 2013
                                              2013 Budget            Actual
Operated drilling and completion costs       $       600.0    $             210.5
Non-operated drilling and completion costs           140.0                   38.5
   Total drilling and completion costs       $       740.0    $             249.0

Salt water disposal wells and facilities     $        23.0    $               5.2
Leasehold acquisitions                                12.0                    1.9
   Total capital expenditures                $       775.0    $             256.1

Asset retirement obligations                 $           -    $               0.5
Capitalized interest                                     -                    8.5

Total capitalized costs                      $       775.0    $             265.1

During the three months ended March 31, 2013, we incurred capital expenditures of $256.1 million related to our oil field operations. We continue to operate seven drilling rigs and are experiencing efficiency gains in drilling days, where we are now averaging approximately 20 days to drill wells and run and cement production liners. The costs associated with wells in progress increased by approximately $46.0 million from December 31, 2012 to March 31, 2013 as a result of scheduling our drilling rigs on four well pads during the winter months, combined with our completion schedule that was designed for anticipated inclement winter weather. In addition, we incurred pre-drill costs, such as site preparation, infrastructure, and began pre-setting surface casing, during the first quarter of 2013 related to wells that will be drilled during the remaining quarters of 2013. By setting surface casing with workover rigs, we can reduce the number of drilling days needed by our rigs. As we exit the winter months and experience improved weather conditions, we will re-engage our second completion crew, which will work down the number of wells waiting on completion.

As a result of operating a seventh rig longer than expected and efficiency gains in the field, as discussed above under "Operation Update", we are currently ahead of the drilling pace set forth in our full-year capital expenditures guidance. We intend to release one drilling rig in the second quarter 2013. As we move through 2013, we will continue to monitor the timing of our drilling and completion activities and, if necessary, we will adjust our plans accordingly based on crude oil pricing and service costs. We have a staggered rig termination schedule with multiple rigs terminating in 2013, allowing for an adjustment to our rig count to align with our cash flow and capital expenditure projections.

Average well costs continue to decline as the Williston Basin has experienced a significant increase in third party oil field services over the past year. As a result, as well as due to our gained efficiencies discussed above, our completed well costs have trended downward from approximately $11 million at year-end 2012 to approximately $10.5 million in the first quarter of 2013, We expect these costs to trend even lower as we move through 2013 as a result of additional cost savings achieved during the first quarter of 2013.

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Sources of Capital

Cash flow from operations. We expect our cash flow from operations to continue to increase commensurate with our anticipated increase in sales volumes. We have been able to increase our volumes on a quarter over quarter basis for the past three years. This increase is directly related to our successful operations as we have developed our properties and acquisitions. If we are able to continue to drill and complete our wells as anticipated and they produce at rates similar to those generated by our existing wells, subject to the changes in the market price of crude oil, we would expect our production rates and operating cash flows to continue to increase as we continue to develop our properties.

Credit facility. As of March 31, 2013, our maximum credit available under the credit facility was $750.0 million with a borrowing base and aggregate commitments of $450.0 million. As of March 31, 2013, we had available borrowings under the credit facility of $350.0 million. On April 3, 2013, we completed our semi-annual redetermination and also consummated an amendment to the credit facility. As a result, the Company's maximum credit available under the credit facility was increased from $750.0 million to $1.5 billion with a borrowing base increase to $650.0 million, which we elected to limit the aggregate commitments to $550.0 million. The credit facility maturity was extended from October 28, 2016 to April 2, 2018.

As of the date of this filing, we have $135.0 million outstanding under this credit facility, with available borrowings of $415.0 million. The ability to maintain and increase this facility and borrow additional funds is dependent on a number of variables, including our proved reserves, and assumptions regarding the price at which oil and natural gas can be sold. Further, we expect that our borrowing base will increase with the addition of proved properties resulting from our ongoing drilling and completion activities. We are subject to restrictive covenants under the credit facility. For further details on our credit facility and Senior Notes please refer to Note 3-Long-Term Debt under Item 1 in this Quarterly Report.

Capital Requirements Outlook

We are dependent on our anticipated cash flows from operations and the expected borrowing availability under our credit facility to fund our remaining 2013 capital expenditures budget, our obligations under our Senior Notes and other contractual commitments (please refer to Note 3-Long-Term Debt and Note 10-Commitments and Contingencies under Item 1 in this Quarterly Report for further details). While we expect such sources of capital to be sufficient for such purposes, there can be no assurance that we will achieve our anticipated future cash flows from operations, that credit will be available under our credit facility when needed, or that we would be able to complete alternative transactions in the capital markets, if needed. Our ability to obtain financing on commercially reasonable terms is dependent on a number of factors, many of which we cannot control, including changes in our credit rating, interest rates, market perceptions of us and the oil and natural gas exploration and production industry and tax burdens due to new tax laws.

If our existing and potential sources of liquidity are not sufficient to satisfy such commitments and to undertake our currently planned expenditures, we believe that we have the flexibility in our commitments to alter our drilling program. Since we operate the majority of our acreage, we have the ability to adjust our drilling schedule to reflect a change in commodity price or oil field service environment. The majority of our acreage is currently producing and the remaining acreage could be held by production within the primary term of the lease, even with a reduced number of drilling rigs. If we were not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our planned expenditures or restructure our operations (including reducing our rig count and sub-contracting our pressure pumping services agreement, either of which may in certain circumstances result in termination fees depending on the timing and requirements of the underlying agreements), we would be unable to implement our original exploration and drilling program, and we may be unable to service our debt obligation or satisfy our contractual obligations.

Senior Notes

We currently have $800.0 million outstanding under our 8.125% Senior Notes due in December 2019 and $350.0 million outstanding under our 5.50% Senior Notes due in January 2021. The annualized interest to be incurred under both of these Senior Notes is approximately $84.3 million.

For further discussion regarding our Senior Notes, please refer to Note 3-Long-Term Debt under Item 1 in this Quarterly Report.

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Working Capital

As part of our cash management strategy, we frequently use available funds to reduce any balance on our credit facility. Because of this, we generally maintain low cash and cash equivalent balances. Since our principal source of operating cash flows (proved reserves to be produced in later periods) is not considered working capital, we often have low or negative working capital. Our working capital was a deficit of $76.8 million at March 31, 2013, as compared to a deficit of $49.4 million at December 31, 2012.

Registered Offerings

Historically, we have financed our operations, property acquisitions and other capital investments from the proceeds of offerings of our equity and debt securities. We may offer from time to time debt securities, common stock, preferred stock, warrants and other securities or any combination of such securities in amounts, prices and on terms announced when and if the securities are offered. The specifics of any future offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus supplement at the time of any such offering.

Derivative Instruments

We utilize various derivative instruments in connection with anticipated crude oil sales to minimize the impact of product price fluctuations and ensure cash flow for future capital needs. Currently, we utilize swaps and "no premium" collars. Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. If actual commodity prices are higher than the fixed or ceiling prices in our derivative instruments, our cash flows will be lower than if we had no derivative instruments. Conversely, if actual commodity prices are lower than the fixed or floor prices in our derivative instruments, our cash flows will be higher than if we had no derivative instruments.

Cash Flow Analysis

The following is a summary of our change in cash and cash equivalents for the
three months ended March 31, 2013 and 2012 (in thousands):
                                               For the Three Months Ended March 31,        Period to period
                                                    2013                   2012                 change

Net cash provided by operating activities   $         114,573       $          69,051     $        45,522
Net cash used in investing activities       $        (279,870 )     $        (697,173 )           417,303
Net cash provided by financing activities   $         147,822       $         571,423            (423,601 )
Decrease in cash and cash equivalents       $         (17,475 )     $         (56,699 )   $        39,224

Net cash provided by operating activities. The key components of our net cash provided by operating activities are our sales volumes (in particular, our crude oil sales volumes) and commodity prices (in particular, crude oil prices). For the three months ended March 31, 2013 as compared to the three months ended March 31, 2012, our net cash provided by operating activities increased by $45.5 million, primarily from increased crude oil sales volumes attributable to our successful drilling and completions in our core Middle Bakken and Three Forks formations in the Williston basin. Additionally, we utilize derivative instruments, as further discussed under the heading "Operating Results" below, to partially mitigate the impact of decreases in crude oil prices.

Net cash used in investing activities. The primary driver in our net cash used for investing activities is our capital expenditure budget, which consists of both our ongoing drilling and completion expenditures and our acquisition expenditures. For the three months ended March 31, 2013 as compared to the three months ended March 31, 2012, our net cash used in investing activities decreased by $417.3 million. This decrease was attributed to our previously announced property acquisition completed in January 2012 ("2012 Acquisition"), which required $588.4 million in cash, which was partially offset by our significantly increased capital expenditures for drilling and completions during the three months ended March 31, 2013 as compared to the three months ended March 31, 2012.

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Net cash provided by financing activities. For the three months ended March 31, 2013 as compared to the three months ended March 31, 2012, our net cash provided by financing activities decreased by $423.6 million. This was a result of our receipt in January 2012 of $670.6 million in cash held in escrow, which was primarily used to finance our 2012 Acquisition and to repay in full our second lien credit agreement, which was then terminated. This decrease was partially offset by the $343.1 million in net proceeds from the issuance of our 2021 Notes in January 2013. All of the net proceeds from the 2021 Notes were used to repay borrowings on the Company's credit facility. Subsequent to paying off the credit facility with the proceeds from the 2021 Notes, we borrowed an additional $100.0 million under our credit facility.

Our Properties

Williston Basin (154,000 net acres)

Our Williston Basin acreage is located primarily in Dunn, McKenzie and Williams counties, of North Dakota. Our primary geologic targets are the Bakken Pool where our primary objective is the dolomitic, sandy interval between the two Bakken Shales at an approximate vertical depth of 10,300-11,300 feet and the second is the Three Forks, consisting of interbedded fine grain siltstones and dolomite, immediately below the lower Bakken shale. The Williston Basin also produces from many other formations including, but not limited to, the Mission Canyon, Nisku and Red River.

Our operations are in an area that we believe has higher reservoir pressure and a high degree of thermal maturity, which is prospective for both the Middle Bakken and multiple benches within the Three Forks. Based on recent drilling results, along with internal and third party reserve engineering analysis, we expect wells in this area to have economic ultimate recoveries ("EURs") that range from 450 to over 1,000 MBOE.

Our Leasehold

As of March 31, 2013, we had several hundred lease agreements representing
approximately 253,000 gross and 164,000 net acres primarily in the Williston and
Green River Basins. The following table sets forth our gross and net acres of
developed and undeveloped oil and natural gas leases:

                             Undeveloped Acreage(1)              Developed Acreage(2)             Total Acreage
                               Gross              Net             Gross            Net         Gross         Net
Green River Basin
Wyoming                      14,940               4,158          9,116             1,826       24,056        5,984
Colorado                      8,027               3,067          2,974             1,252       11,001        4,319
Williston Basin
Montana                           -                   -          5,224             2,489        5,224        2,489
North Dakota                 87,542              61,911        124,895            89,211      212,437      151,122

Acreage Totals              110,509              69,136        142,209            94,778      252,718      163,914

(1) Undeveloped acreage is lease acreage on which wells have not been drilled . . .

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