The following discussion and analysis should be read in conjunction with the "Selected Financial Data" in Item 6 above and our historical consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K.
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. Our 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 development and exploratory drilling opportunities on high potential conventional and unconventional oil and natural gas prospects.

Our oil and natural gas reserves and operations are primarily concentrated in the Williston Basin of North Dakota and Montana and, to a lesser extent, the Green River Basin of Wyoming and Colorado. The most significant prospects in our portfolio are our assets in the Williston Basin, 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 TFS member, positioned immediately below the Lower Bakken Shale. As of December 31, 2012, we owned an interest in approximately 228,200 gross (154,400 net) acres in the Williston Basin and have an interest in 268 gross (121.9 net) producing wells in the Williston Basin.

Oil and Gas Property Acquisitions
The following is a summary of our acquisitions during the last two fiscal years:

January 2012 Acquisition

On January 10, 2012, we acquired certain oil and gas leaseholds, overriding royalty interests and producing properties located in North Dakota, and various other related rights, permits, contracts, equipment and other assets, including the assignment and assumption of a drilling rig contract (the "January 2012 Acquisition"). The effective date for this acquisition was September 1, 2011. The producing properties acquired in January 2012 contributed revenue to us for the years ended December 31, 2012 and 2011 of $33.6 million and $0, respectively. Oil and gas proved reserves acquired were 11,891.3 MBOE.

We closed this acquisition for aggregate consideration of approximately $638.2 million. This consideration was comprised of (i) 5,055,612 shares of the Company's common stock and (ii) cash consideration in an amount equal to approximately $588.4 million. We funded the cash balance due at closing through the release from escrow of the proceeds from our November 2011 high yield debt and equity offering.

Through this acquisition, we acquired approximately 50,000 net leasehold acres and net production of approximately 3,600 barrels of oil equivalent per day located primarily in McKenzie and Williams Counties, N.D. We operate substantially all of the leasehold acquired through this acquisition.

October 2011 Acquisition

On October 28, 2011, we acquired interests in approximately 13,400 net acres of Williston Basin leaseholds, and related producing properties located primarily in Williams County, North Dakota along with various other related rights, permits, contracts, equipment and other assets. The seller in this transaction received cash consideration of approximately $248.2 million. The effective date for the acquisition was August 1, 2011. The producing properties acquired in October 2011 contributed revenue to us for the years ended December 31, 2012 and 2011 of $27.2 million and $5.6 million, respectively.

June 2011 Acquisition

On June 30, 2011, we acquired interests in approximately 25,000 net acres of Williston Basin leaseholds and related producing properties located in McKenzie County, North Dakota along with various other related rights, permits, contracts, equipment and other assets for a combination of cash and stock. The seller in this transaction received 2,500,000 shares of the Company's common stock valued at approximately $14.0 million and cash consideration of approximately $71.5 million. The effective date for the acquisition was April 1, 2011. The producing properties acquired in June 2011 contributed revenue to us for the years ended December 31, 2012 and 2011 of $1.5 million and $1.4 million, respectively.

2012 Capital Expenditures and 2013 Capital Budget

The following table sets forth our actual capital expenditures for the years
ended December 31, 2012, 2011, and 2010 and our capital expenditures budget for
2013. Capital expenditures include cash expenditures, accrued expenditures, oil
and gas property acquisitions through the issuance of common stock and are net
of divestitures (in millions).

                                                          For the Years Ended December 31,
                                          2013 Budget       2012 Actual       2011 Actual       2010 Actual
Costs incurred:
Acquisitions(1)
Proved oil and gas properties           $         -       $       322.8     $       152.5     $        32.2
Unproved oil and gas properties                   -               313.1             168.0              77.2
Asset retirement obligations                      -                 0.8               0.3               0.2
Total acquisitions                                -               636.7             320.8             109.6

Capital Expenditures
Operated drilling and completion
costs                                         600.0               664.5             194.2              63.3
Non-operated drilling and completion
costs                                         140.0               145.9              66.4               3.5
Total drilling and completion costs           740.0               810.4             260.6              66.8

Salt water disposal wells and
facilities                                     23.0                10.2                 -                 -
Leasehold acquisitions                         12.0                17.9              14.9              18.5
Total capital expenditures                    775.0               838.5             275.5              85.3

Asset retirement obligations                      -                 4.1               1.3               0.6
Capitalized interest                              -                46.0               8.4               0.5
Total capital expenditures including
non-cash items                                775.0               888.6             285.2              86.4

Total capitalized costs                 $     775.0       $     1,525.3     $       606.0     $       196.0

(1) Includes acquisitions accounted for as business combinations.

The table below summarizes the wells spud and completed during the year ended December 31, 2012 as a result of our 2012 capital expenditures. For the year ended December, 31 2012, we incurred capital expenditures of $810.4 million related to drilling and completion operations (exclusive of our January 2012 Acquisition). At December 31, 2012, we had 18 gross (14.0 net) operated and 16 gross (1.5 net) non-operated wells waiting on completion.

                                          Spud          Completed
                                     Gross     Net    Gross     Net
For the Year Ended December 31, 2012
Operated wells                          69    57.1       64    52.4
Non-operated wells                      77    13.6       60    10.2
                                       146    70.7      124    62.6

Industry wide, exploration and development activity in the Williston Basin continued at a high level in 2012. During the year, our drilling operations benefited from improved efficiencies resulting in decreased spud-to-rig-release drilling times. As the Basin has experienced a significant increase in third party oil field services over the past year and operators gain efficiencies through more pad drilling, we have seen improved field services and reduced costs. During the year, our completed well costs trended downward from approximately $12 million per well, including surface facilities and pipeline connections, to approximately $11 million by year end. Further, we recently renegotiated agreements with certain suppliers, which we expect will reduce our drilling and completion costs to approximately $10 million per well in early 2013.

Our Board of Directors approved a $775.0 million capital expenditure budget for 2013, all of which is allocated to oil and gas activities in the Williston Basin of North Dakota. We have allocated $600.0 million to the drilling and completion of 75 gross (61 net) operated wells; $140.0 million to non-operated drilling and completion activities for 14 net wells; and $35.0 million for water disposal systems, well connections and acreage acquisitions. We anticipate funding this capital program through existing cash on hand, our expected cash flow from operations, and borrowing capacity expected to be available under our credit facility. As of the date of this filing, we had a borrowing base and total commitment for the credit facility of $450.0 million, of which $400.0 million is currently available.

The following chart illustrates our expected capital allocation by operating area:

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We are currently operating seven drilling rigs and anticipate operating six to seven drilling rigs for the majority of 2013. Our rig termination schedule allows us to adjust capital expenditures in reaction to economic conditions such as a decline in crude oil prices.

We are proceeding with a pilot program to test 12 wells within a drilling spacing unit in each of our Polar and Smokey operating areas. In each project, six wells will target the Middle Bakken and six wells will target intervals within the Three Forks Formation.

The Polar pilot project wells are being drilled from three four-well pads. Geologic and geophysical work on the DSU will include cores and high-resolution logs to evaluate the Middle Bakken and all benches of the TFS. In addition, a micro seismic program is planned to further evaluate completion procedure effectiveness.

In our Smokey block, two wells within the test DSU are now producing, and three additional well bores have recently been drilled into the same DSU. We expect to drill the remaining seven wells following drilling of the Polar pilot program.

Water disposal and oil and gas lines are being constructed in each of the test areas and should be operational before completion activities begin. Results from these pilot projects will be evaluated throughout 2013.

Our 2013 capital expenditure budget is subject to various factors, including market conditions, oilfield services and equipment availability, commodity prices and drilling results. While we continue to explore opportunities to expand our acreage position, our current budget is primarily allocated to drilling and completing wells. If we choose to pursue the acquisition of significant additional leaseholds, we would need to increase our budget accordingly.

Other factors that could cause us to further adjust our capital expenditure budget include, among other things, increases or decreases in service and material costs, the formation of joint ventures with other exploration and production companies, the divestiture of non-strategic assets, changes in commodity prices or well performance that differ from our forecasts, any of which could affect our operating cash flow.

Liquidity and Capital Resources
Our 2013 drilling program is designed to provide flexibility in identifying suitable well locations and in the timing and size of capital investment. We plan to finance our 2013 capital expenditure budget of $775.0 million and our obligations under our Senior Notes and other contractual commitments through existing cash on hand, cash flows from operations and borrowing capacity expected to be available under our credit facility, as discussed in more detail below:

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. 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 December 31, 2012, our maximum credit available under the credit facility is $750.0 million with a current borrowing base and aggregate commitments of $450.0 million. As of December 31, 2012, we had available borrowings under the credit facility of $155.0 million. All proceeds from the issuance of the $350.0 million aggregate principal amount of 5.50% senior notes (defined below) in January 2013 were used to reduce amounts outstanding under our credit facility. As of the date of this filing, we have $400.0 million available under this credit facility. 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 5-Long-Term Debt under Item 8 in this Annual 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 2013 capital expenditures budget, our obligations under our Senior Notes and other contractual commitments (please refer to Note 5-Long-Term Debt and Note 14-Commitments and Contingencies under Item 8 in this Annual 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

8.125% Senior Notes due 2019. In November 2011, we issued in a private placement at par $650.0 million principal amount of 8.125% senior notes due December 1, 2019 (which notes were subsequently exchanged for SEC registered notes pursuant to the Exchange Offer (defined below) (the "Original 2019 Notes"). The net proceeds from such issuance were primarily used to finance our January 2012 Acquisition and to repay in full our second lien credit agreement, which was then terminated. In May 2012, we issued in a private placement an additional $150.0 million aggregate principal amount of our senior notes due December 1, 2019 at 104.0% of par, resulting in a $6.0 million premium on the issuance (which notes were subsequently exchanged for SEC registered notes pursuant to the Exchange Offer (the "Follow-On 2019 Notes", and together with the "Original 2019 Notes", the "2019 Notes"). The net proceeds from such issuance were used to repay all borrowings on our credit facility and to fund our capital expenditure program and general corporate purposes. The interest on our 2019 Notes is payable on June 1 and December 1 of each year. On July 20, 2012, the Company filed a registration statement on Form S-4 (No. 333-182783, amended on October 9, 2012 and declared effective by the SEC on October 11, 2012) with the SEC in accordance with registration rights agreements associated with the privately placed 2019 Notes. On October 12, 2012, the Company commenced a registered exchange offer ("Exchange Offer") pursuant to which all of the holders of the privately placed 2019 Notes exchanged their notes for SEC-registered 2019 Notes. The Exchange Offer closed on November 16, 2012.

5.50% Senior Notes due 2021. In January 2013, we issued at par $350.0 million principal amount of 5.50% senior notes due January 15, 2021 (the "2021 Notes", and together with the 2019 Notes, the "Senior Notes"). All of the net proceeds from this issuance were used to repay borrowings on our credit facility. The interest on our 2021 Notes is payable on January 15 and July 15 of each year. In connection with the sale of our 2021 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 2021 Notes for SEC-registered notes and (2) to file, under certain circumstances, a shelf registration statement to cover resales of the 2021 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 2021 Notes.

For further discussion regarding our Senior Notes, please refer to Note 5-Long-Term Debt under Item 8 in this Annual Report.

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 future years) is not considered working capital, we often have low or negative working capital. Our working capital was a deficit of $49.4 million at December 31, 2012, as compared to a positive $72.8 million at December 31, 2011.

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 currently have on file with the SEC a universal shelf registration statement to allow us to offer an indeterminate amount of securities in the future. Under the registration statement, 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
years ended December 31, 2012, 2011 and 2010 (in thousands):
                                                         For the Years Ended December 31,
                                                        2012            2011           2010

Net cash provided by operating activities          $    272,679     $   53,913     $   10,315
Net cash used in investing activities              $ (1,348,078 )   $ (590,749 )   $ (200,009 )
Net cash provided by financing activities          $  1,017,855     $  517,242     $  266,007
Increase (decrease) in cash and cash equivalents   $    (57,544 )   $  (19,594 )   $   76,313

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 year ended December 31, 2012 as compared to the year ended December 31, 2011, our net cash provided by operating activities increased by $218.8 million, primarily from increased crude oil sales volumes attributable to our successful drilling and completions in our core Middle Bakken and TFS formations in the Williston basin. Additionally, we utilize derivative instruments, as further discussed in the Operating Results section 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 year ended December 31, 2012 as compared to the year ended December 31, 2011, our net cash used in investing activities increased by $757.3 million. This increase is primarily attributed to our January 2012 Acquisition, which required $588.4 million in cash, and secondarily, to our significantly increased capital expenditures for drilling and completions during the year ended December 31, 2012 as compared to the year ended December 31, 2011.

Net cash provided by financing activities. For the year ended December 31, 2012 as compared to the year ended December 31, 2011, our net cash provided by financing activities increased by $500.6 million. This was a result of our receipt from escrow of $670.6 million related to the issuance of our Original 2019 Notes in November 2011 ($588.4 million of which was used to fund our January 2012 Acquisition and $100.0 million of which was used to repay our second lien credit agreement) and the receipt of $151.8 million in net proceeds from the issuance of our Follow-On 2019 Notes in May 2012.

Operating Results

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. 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. The following table discloses our oil and gas sales volumes from the Bakken field and from our other fields combined and in total, for the periods indicated:

                              For the Years Ended December 31,
                                  2012               2011      2010
Sales Volume (Bakken):
Oil (MBbls)                  4,686.9               1,304.7    402.3
Gas (MMcf)                   3,259.1                 472.3     11.1
Sales Volume (Other):
Oil (MBbls)                     17.2                  39.8     30.0
Gas (MMcf)                      42.9                  50.4    151.8
Sales Volume (Total):
Oil (MBbls)                  4,704.1               1,344.5    432.3
Gas (MMcf) (1)               3,302.0                 522.7    162.9
Sales volumes (MBOE)         5,254.4               1,431.6    459.5

(1) Does not include production of natural gas that was flared, all of which is related to the Bakken field. For the years ended December 31, 2012, 2011 and 2010, we flared gas in the amounts of 3,311.2 MMcf, 806.7 MMcf and 282.7 MMcf, respectively.

Sales prices received, and costs incurred, presented on a per BOE basis, for the years ended December 31, 2012, 2011 and 2010 are summarized in the following table:

                                                       For the Years Ended December 31,
                                                      2012            2011           2010
Sales Price:
Oil ($/Bbls)                                      $     83.00     $    86.05     $    69.89
Gas ($/Mcf)(1)                                    $      5.53     $     8.22     $     4.81
BOE ($/BOE)                                       $     77.78     $    83.81     $    67.46

Commodity Price Risk Management Activities
($/Sales BOE):
Realized gain (loss)                              $      2.57     $    (2.72 )   $    (0.88 )
Production costs ($/Sales BOE):
Lease operating expenses                          $      6.04     $     8.67     $     7.03
Production and property taxes                     $      8.34     $     9.04     $     7.49
Gathering, transportation, marketing              $      1.89     $     1.07     $     0.26
DDA                                               $     29.62     $    22.40     $    17.92
G&A                                               $      6.57     $    13.62     $    26.53
Stock?based compensation                          $      2.12     $     3.63     $     9.70

(1) Average gas price received at the wellhead includes proceeds from natural gas liquids under percentage of proceeds contracts.