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KOG > SEC Filings for KOG > Form 10-Q on 31-Oct-2013All Recent SEC Filings

Show all filings for KODIAK OIL & GAS CORP



Quarterly Report

Forward-Looking Statements
The information discussed in this quarterly report on Form 10-Q includes "forward­looking 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 forward­looking statements. These forward­looking 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 forward­looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward­looking statements as a result of certain factors, including those detailed in the section entitled "Risk Factors" included in our Annual Report on Form 10-K. All forward­looking 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 forward­looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.


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. We have developed an oil and natural gas asset base of proved reserves, as well as a portfolio of development and exploratory drilling opportunities on high resource-potential leasehold. We intend to continue to expand our asset base by developing our current lands as well as evaluating and investing in core acquisitions.

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 September 30, 2013, we owned an interest in approximately 334,000 gross (192,000 net) acres in the Williston Basin and have an interest in 546 gross (221.3 net) producing wells in the Williston Basin.

Recent Developments

Acquisitions and Divestitures

On July 12, 2013, we closed our acquisition of core Williston Basin producing properties and undeveloped leasehold from an unaffiliated private oil and gas company ("July 2013 Acquisition"). The purchase price for the July 2013 Acquisition was $680.0 million. Post-closing adjustments were $51.8 million, including $22.1 million in working capital items and $29.7 million of cash flow adjustments to reflect the acquisition's March 1, 2013 effective date. The seller received aggregate consideration of approximately $731.8 million in cash.

Included in the acquisition were approximately 42,000 net leasehold acres located in McKenzie and Williams Counties, North Dakota and net production during July 2013 of approximately 5,500 barrels of oil equivalent per day. The acquired leasehold included 35 controlled drilling spacing units and was largely held by production. The southern Williams County lands, approximating 14,000 net acres, are adjacent to our core Polar area. An additional 25,000 net acres are located in our Ursid area in McKenzie County.

During the third quarter of 2013, through various trades, acquisitions and divestitures, we divested approximately 3,700 net acres, which primarily consisted of certain producing properties and undeveloped leasehold that we acquired in our July 2013 Acquisition. Net proceeds from all of the transactions were approximately $36.7 million. As a result of these transactions, we were able to divest or trade out of non-operated units and increase our working interest in operated units.

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Expanded Credit Facility and Senior Note Offering

We funded the July 2013 Acquisition through borrowings under our revolving credit facility. In connection with the acquisition and reflecting year-to-date completion activities, Kodiak and its lending group entered into an amendment to our credit facility to increase our borrowing base and aggregate commitments under our existing revolving credit facility to $1.1 billion. In connection with the issuance of the 2022 Notes (as discussed below), the lenders under our credit facility agreed to a waiver of provisions that provided for a reduction in the borrowing base under the credit facility upon consummation of the offering.

On July 26, 2013, we issued at par $400.0 million principal amount of 5.50% senior notes due February 1, 2022 (the "2022 Notes"). All of the net proceeds from this issuance were used to repay borrowings on our revolving credit facility.

Operational Update

During the third quarter of 2013, we completed 29 gross (24.5 net) operated wells and participated in the completion of 37 gross (6.6 net) non-operated wells. From late May to late August 2013, we operated with two full-time, 24-hour-per-day completion crews. The second completion crew was released for the month of September 2013 and was brought back in mid October 2013. The Company plans to utilize two crews through the remainder of the year. We expect to complete 29 gross (21.5 net) operated wells during the fourth quarter.

We currently operate seven drilling rigs and participate for an approximate 50% working interest in the drilling activity of one non-operated rig in its Dunn County area of mutual interest (AMI). In addition, we participate for a minority working interest in numerous non-operated properties with other operators. At this time, our operated rigs are drilling in the following prospect areas: one rig operating in Dunn County, three rigs in the Polar project area in southern Williams County, one rig in each of the Smokey and Koala project areas in McKenzie County, and one rig in the Wildrose project area in northern Williams County.

The following tables summarize the wells spud and completed during the three and nine months ended September 30, 2013:

                             For the Three Months Ended September 30, 2013
                                         Spud                          Completed
                                     Gross                    Net    Gross     Net
Operated wells             29.0                              21.9     29.0    24.5
Non-operated wells         22.0                               1.3     37.0     6.6
                           51.0                              23.2     66.0    31.1

                             For the Nine Months Ended September 30, 2013
                                        Spud                         Completed
                                    Gross                   Net    Gross     Net
Operated wells              74.0                           59.1     74.0    60.6
Non-operated wells          65.0                            6.2     80.0    13.2
                           139.0                           65.3    154.0    73.8

Downspacing Tests

Our program to test 12 wells within a 1,280-acre drilling spacing unit (DSU) continues in the Polar and Smokey operating areas. All wells in both project areas have been completed and are on production. The wells in the Polar area were drilled and completed simultaneously, while the wells in Smokey were drilled and completed in various quarters, in an attempt to evaluate the proper development of future DSU's. The two pilot programs have tested well bore spacing of approximately 800 feet between wells (or roughly 210 acre drainage) in each of the two formations in the Middle Bakken and Three Forks formations.

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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 nine months ended September 30, 2013:

                                                               Nine Months Ended
                                                               September 30, 2013
                                              2013 Budget            Actual
Capital Expenditures
  Drilling and completion costs              $       965.0    $             790.4
  Salt water disposal wells and facilities            23.0                   13.1
  Leasehold acquisitions                              12.0                    6.3
     Total capital expenditures              $     1,000.0    $             809.8

Acquisitions, Net of Divestitures
  Proved oil and gas properties                               $             385.8
  Unproved oil and gas properties                                           285.8
                                                              $             671.6

  Asset retirement obligations                                $               4.2
  Capitalized interest                                                       25.6

  Total capitalized costs                                     $           1,511.2

Average well costs continue to decline in the Williston Basin. Our completed well costs averaged approximately $9.8 million in the third quarter of 2013 and have trended downward throughout the year, with current costs estimates below $9.5 million. The declining well costs result from a combination of field efficiency gains and the reduction of third party oil field service costs.

During the nine months ended September 30, 2013, we incurred capital expenditures of $790.4 million related to our oil field operations to complete 73.8 net wells. We expect our fourth quarter capital spend to be less than that of the third quarter due to lower well costs on a quarter-over-quarter basis and our plan to drill and complete fewer net wells during the fourth quarter of 2013 as compared to the third quarter of 2013. This is primarily attributable to one less non-operated rig drilling in Dunn County and a lower working interest in wells being drilled and completed in the fourth quarter of 2013.

As we develop our plans for 2014, we will 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 rigs terminating in 2014 through 2015, allowing for an adjustment to our rig count to align with our cash flow and capital expenditure projections.

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 sales volumes on a quarter over quarter basis for the past several years. This increase is directly related to our successful operations as we have developed our properties and, to a lesser extent, cash flows from acquired properties. 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.

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Credit facility. As of September 30, 2013, our maximum credit available under the credit facility was $1.5 billion with a borrowing base and aggregate commitment of $1.1 billion. As of September 30, 2013, we had available borrowings under the credit facility of $462.0 million.

As previously discussed, on July 12, 2013 in conjunction with the closing of the July 2013 Acquisition, we amended our credit facility to increase our borrowing base and aggregate commitments under our credit facility to $1.1 billion. 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 please refer to Note 4 - 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 capital expenditures budget, our obligations under our Senior Notes and other contractual commitments (please refer to Note 4 - Long-Term Debt and Note 11 - 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 development program. We operate the majority of our leasehold, therefore we have the ability to adjust our drilling schedule to reflect a change in commodity prices or oil field service environment. At this time the majority of our leasehold is held by production and the remaining acreage can be drilled within the primary term of the lease, even with a reduced number of drilling rigs.

Senior Notes

As of the date of this filing we have $800.0 million outstanding under our 8.125% Senior Notes due in December 2019, $350.0 million outstanding under our 5.50% Senior Notes due in January 2021 and $400.0 million outstanding under our 5.50% Senior Notes due in February 2022. The annualized interest to be incurred under all of the Senior Notes is approximately $106.3 million.

In July 2013, we issued at par $400.0 million principal amount of 5.50% Senior Notes due February 1, 2022. All of the net proceeds from this issuance were used to repay borrowings on our credit facility. The interest on our 2022 Notes is payable on February 1 and August 1 of each year. In connection with the sale of our 2022 Notes, we entered into a registration rights agreement pursuant to which we agreed (1) to file an exchange offer registration statement to allow the holders to exchange the 2022 Notes for SEC-registered notes and (2) to file, under certain circumstances, a shelf registration statement to cover resales of the 2022 Notes. If we fail to complete the registered exchange offer or the shelf registration statement has not been declared effective within specified time periods, we will be required to pay liquidated damages by way of additional interest on the 2022 Notes.

On September 20, 2013, we filed a registration statement on Form S-4 (No. 333-191281) in accordance with the registration rights agreements associated with the privately placed 2021 Notes and 2022 Notes. The SEC declared the registration statement effective on October 29, 2013. On October 30, 2013, the Company commenced registered exchange offers pursuant to which all holders of the privately placed 2021 Notes and 2022 Notes may exchange their notes for registered 2021 Notes and 2022 Notes, respectively. The Company expects to close each exchange offer on December 2, 2013. For further discussion regarding our Senior Notes, please refer to Note 4 - 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 $108.8 million at September 30, 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 in part from the proceeds from 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
nine months ended September 30, 2013 and 2012 (in thousands):

                                                For the Nine Months Ended September 30,        Period to period
                                                     2013                     2012                  change

Net cash provided by operating activities   $           385,535       $           203,255     $       182,280
Net cash used in investing activities       $        (1,464,986 )     $        (1,120,767 )          (344,219 )
Net cash provided by financing activities   $         1,073,709       $           837,658             236,051
Decrease in cash and cash equivalents       $            (5,742 )     $           (79,854 )   $        74,112

Net cash provided by operating activities. The key component of our net cash provided by operating activities is the revenue derived from our crude oil sales and the crude oil prices received for those sales. For the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012, our net cash provided by operating activities increased by $182.3 million, primarily due to the increase in crude oil sales volumes of 3.3 million barrels. Our revenues are directly affected by oil and natural gas commodity prices, which can fluctuate dramatically. The commodity prices are largely beyond our control and are difficult to predict. We have seen significant volatility in oil and natural gas prices in recent years. As such, 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. For the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012, our net cash used in investing activities increased by $344.2 million. This increase was primarily attributed to an increase in acquisitions, net of divestitures, of $86.0 million and our increased capital expenditures of $240.8 million from drilling and completions activities.

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Net cash provided by financing activities. For the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012, our net cash provided by financing activities increased by $236.1 million. This increase was primarily the result of the increase in proceeds received from our senior notes offerings and net borrowings under our credit facility. For the nine months ended September 30, 2013, proceeds from our issuance of senior notes increased by $594.0 million and net borrowings under our credit facility increased by $328.0 million, as compared to the same period in 2012. These increases were offset by the $670.6 million receipt in January 2012 of cash held in escrow, which was used to fund our property acquisition completed in January 2012.

Our Properties

Williston Basin

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 350 to over 1,000 MBOE.

Our Leasehold

As of September 30, 2013, we had several hundred lease agreements representing
approximately 368,000 gross and 202,000 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
Williston Basin
North Dakota                143,245              78,492        190,515          113,098      333,760      191,590
Green River Basin
Wyoming                      14,727               4,105          9,009            1,799       23,736        5,904
Colorado                      8,027               3,067          2,974            1,252       11,001        4,319
Acreage Totals              165,999              85,664        202,498          116,149      368,497      201,813

(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.

We believe we have satisfactory title, in all material respects, to substantially all of our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Substantially all of our proved oil and natural gas properties are pledged as collateral for borrowings under our credit facility.

Substantially all of the leases summarized in the preceding table will expire at the end of their respective primary terms unless (i) we have obtained production from the acreage subject to the lease prior to the end of the primary term, in which event the lease will remain in effect until the cessation of production; or (ii) the existing lease is renewed; or (iii) it is contained within a federal unit. Based on our current drilling plans we do not expect to lose any material acreage through expiration. The following table sets forth the gross and net acres of undeveloped land subject to leases that will expire during the current year and the following three years and have no options for renewal or are not included in federal units:

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Expiring Acreage
Year Ending            Gross         Net
December 31, 2013      1,110          563
December 31, 2014     14,172       10,715
December 31, 2015     12,908        9,601
December 31, 2016      6,450        5,433
Total                 34,640       26,312

Operating Results

Sales Volumes, Average Sales Prices, and Production Costs

The Bakken is the only field (as such term is used within the meaning of
applicable regulations of the SEC) that contains more than 15% of our total
proved reserves. At December 31, 2012, this field contained 99.8% of our total
proved reserves. The following table discloses our oil and gas sales volumes for
the periods indicated:
                                 For the Three Months Ended         For the Nine Months Ended
                                        September 30,                     September 30,
                                    2013             2012             2013             2012
Sales Volume:
Oil (MBbls)                           2,921            1,287            6,475            3,210
Gas (MMcf)                            2,018            1,028            5,079            2,201
Sales volumes (MBOE) (1)              3,257            1,459            7,322            3,577

Average Daily Sales Volumes
Oil (MBbls/day)                        31.8             14.0             23.7             11.7
Gas (MMcf/day)                         21.9             11.2             18.6              8.0
Sales volumes (MBOE/day) (1)           35.4             15.9             26.8             13.1

(1) We convert Mcf of gas equivalent to oil at a ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

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