Summary of BRIGHAM EXPLORATION CO

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following updates information as to our financial condition provided in our 2008 Annual Report on Form 10-K, and analyzes the changes in the results of operations between the three and six month periods ended June 30, 2009 and June 30, 2008. For definitions of commonly used oil and gas terms as used in this Form 10-Q, please refer to the "Glossary of Oil and Gas Terms" provided in our 2008 Annual Report on Form 10-K. Statements in the following discussion may be forward-looking and involve risk and uncertainty. The following discussion should be read in conjunction with our Consolidated Financial Statements and Notes hereto.
General Overview
We are an independent exploration, development and production company that utilizes advanced exploration, drilling and completion technologies to systematically explore for, develop and produce domestic onshore oil and natural gas reserves. We focus our activities in provinces where we believe these technologies, including 3-D seismic imaging, horizontal drilling and multi-stage fracture stimulations, can be used to effectively maximize our return on invested capital.
Historically, our exploration and development activities have been focused in the Onshore Gulf Coast, the Anadarko Basin and West Texas. Beginning in late 2005, we began to acquire acreage within the Williston Basin in North Dakota and Montana, and since then have invested in excess of $170 million on drilling, land and seismic in this region. In late 2007, the majority of our drilling capital expenditures shifted from our historically active areas in the Onshore Gulf Coast, the Anadarko Basin and West Texas to the Williston Basin, where we are currently targeting Bakken, Three Forks and Red River objectives. At present, we have approximately 290,000 net leasehold acres in the Williston Basin and have identified over 800 horizontal drilling locations on our acreage. Our business strategy is to create value for our stockholders by growing reserves, production volumes and cash flow through exploration and development drilling in areas where we can use technology to generate attractive rates of return on our invested capital. Key elements of our business strategy include:
• Focus on Provinces;

• Leverage Our Engineering and Operational Expertise;

• Capitalize on Exploration Successes Through Disciplined Development Activities;

• Enhance Returns Through Operational Control; and

• Internally Generate an Inventory of High Quality Exploratory Prospects.

Overview of Second Quarter 2009
In May 2009, we completed a public offering of common stock pursuant to a shelf registration statement. We sold 36,292,117 shares at a price of $2.75 and received net proceeds of $93.5 million after underwriting fees and offering expenses. We used the net proceeds from the offering to repay $35 million of our outstanding indebtedness under our Senior Credit Facility. We are using the remaining net proceeds to fund our expanded capital budget in 2009 as well as fund a portion of our 2010 capital budget.
In May 2009, in connection with our common stock offering, we increased our 2009 capital budget to $64.5 million from $37.1 million. The increase in our budget was used to fund the restart of our operated Bakken and Three Forks drilling program in the Williston Basin in North Dakota. We anticipate that our revised 2009 budget will allow us to complete three wells that we deferred completing in early 2009 due to low commodity prices, high service costs and high differentials. In addition, our expanded 2009 capital budget is anticipated to allow us to drill two new long lateral horizontal wells in Williams County, North Dakota. To date, we have completed one of the three wells that we deferred completing in early 2009 and have commenced drilling one of the two new long lateral wells. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview of Second Quarter 2009 Operational Results - Rocky Mountain Province - Williston Basin.

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Second quarter 2009 oil and natural gas prices, excluding realized and unrealized derivative hedging results, decreased 60% and 71%, respectively, from the second quarter 2008. In the second quarter 2009, the average sales price that we received for oil, excluding realized and unrealized derivative hedging results, was $49.41 per barrel, which represents a $72.81 per barrel decrease from that in the second quarter 2008. In the second quarter 2009, the average sales price that we received for natural gas, excluding realized and unrealized derivative hedging results, was $3.50 per Mcf, which represents an $8.43 per Mcf decrease from that in the second quarter 2008.
Our second quarter 2009 production averaged 27.2 MMcfe per day, which represents a 10% decrease from the second quarter 2008. The natural production decline from our wells, decreased drilling activity, and the higher than forecasted decline rates associated with our Bayou Postillion wells in Southern Louisiana led to reduced production. During the second quarter 2009, our oil volumes increased by 28% to approximately 164,000 barrels versus that in the second quarter 2008 as a result of our increased activity level in the Williston Basin. Our second quarter 2009 oil and natural gas revenues, including hedge settlements but excluding unrealized hedging gains and losses, were down $21.0 million, or 59%, compared to that in the second quarter 2008. Oil revenues in the second quarter 2009, including hedge settlements but excluding unrealized hedging gains and losses, decreased $6.2 million from the second quarter 2008. Lower oil prices reduced revenues by $11.9 million while both higher production volumes and hedge settlements increased revenues by $4.4 million and $1.4 million, respectively. Natural gas revenues in the second quarter 2009, including hedge settlements but excluding unrealized hedging gains and losses, decreased $14.9 million compared to the second quarter 2008. Lower natural gas prices and reduced production volumes decreased revenues $12.3 million and $5.8 million, respectively, while increased hedge settlements increased revenues by $3.3 million.
Second quarter 2009 operating income decreased $8.6 million from that in the second quarter last year. This decrease was attributable to the decline in commodity prices, natural gas volumes and higher lease operating expense. These items were partially offset by higher oil volumes and lower depletion, general and administrative and production tax expenses.
As of June 30, 2009, we had $73.4 million in cash and marketable securities and $404.4 million in total assets.
Overview of Second Quarter 2009 Operational Results Rocky Mountain Province
Williston Basin
Following our equity offering in May 2009, we restarted our operated drilling program in the Williston Basin. In June, we re-entered the Anderson 28-33 #1H and began drilling the horizontal portion of the wellbore in the Bakken formation. Currently, we are fracture stimulating the well with 24 stages planned. The Anderson is located approximately 2 miles west of our Carkuff 22 #1H discovery. We own an approximate 66% working interest and 55% net revenue interest in the Anderson well.
In late June, we began fracture stimulating the Strobeck 27-34 #1H, which is a long lateral Three Forks well, with 20 stimulation stages. The Strobeck well is located approximately one mile west of our operated Carkuff 22 #1H in Mountrail County, North Dakota. We own an approximate 77% working interest and a 63% revenue interest in the well.
In late July, we began completion operations on the Figaro 29-32 #1H, which is a long lateral Bakken well, with 20 stimulation stages. Currently, we are continuing completion operations. We own an approximate 90% working interest and a 72% revenue interest in the well.
Onshore Gulf Coast Province
Southern Louisiana
In May 2009, we successfully brought on line our third joint venture well with Clayton Williams Energy, Inc., the Breton Sound SL 19054 #1. The Breton Sound well was completed from 60 feet of pay. We own an approximate 50% working interest and a 39% revenue interest in the well.

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Subsequent Events
On July 24, 2009, we entered into the Fifth Amendment to our Senior Credit Facility. The amendment extended the maturity of the agreement to July 24, 2012, amended our Interest Coverage Ratio (as defined in the Senior Credit Facility), added a Net Leverage Ratio (as defined in the Fifth Amendment) and requires us to maintain $10 million in liquidity until our preferred stock is redeemed in October 2010. Our Interest Coverage Ratio for the four quarters ended as of June 30, 2009 and September 30, 2009 must be a minimum of 2.50 to 1.00, for the four quarters ended as of December 31, 2009 and March 31, 2010 must be a minimum of 2.00 to 1.00 and for the four quarters thereafter must be a minimum of 2.50 to 1.00. Our Net Leverage Ratio beginning with the quarter ended September 30, 2009 through September 30, 2010 must be not greater than 4.50 to 1.00, ending December 31, 2010 and March 31, 2011 must be not greater than 4.25 to 1.00 and thereafter must be not greater than 4.00 to 1.00. Results for the Three and Six Months Ended June 30, 2009 Comparison of the three month and six month periods ended June 30, 2009 and 2008.

Production volumes

                                              Three months ended June 30,                  Six months ended June 30,
                                           2009           % Change        2008         2009          % Change        2008

Oil (MBbls)                                    164               28 %        128           338              38 %        245
Natural gas (MMcf)                           1,460              (25 %)     1,947         3,302             (20 %)     4,139
Total (MMcfe)(1)                             2,444              (10 %)     2,715         5,328              (5 %)     5,609
Average daily production (MMcfe/d)(2)         27.2              (10 %)      30.2          29.6              (5 %)      31.2
Average daily production (Boe/d)(2)          4,526              (10 %)     5,027         4,933              (5 %)     5,193

(1) MMcfe is defined as one million cubic feet equivalent of natural gas, determined using the ratio of six MMcf of natural gas to one MBbl of crude oil, condensate or natural gas liquids.

(2) Average daily production is calculated using 30 days per calendar month.

Natural gas represented 60% of our second quarter 2009 production volumes and 62% of our first six months 2009 production volumes, compared to 72% in the second quarter 2008 and 74% in the first six months 2008.

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Revenues, Commodity Prices and Hedging
The following table sets forth our production volumes, the average prices we
received before hedging, the average prices we received including derivative
settlement gains (losses) and the average prices including derivative
settlements and unrealized gains (losses).

                                 Three months ended June 30,                     Six months ended June 30,
                             2009          % Change          2008           2009         % Change          2008

Oil revenue:
Oil revenue               $    8,105             (48 %)    $  15,640      $  14,055            (48 %)    $  26,797
Oil derivative
settlement gains
(losses)                        (222 )           (86 %)       (1,601 )          860             NM          (2,187 )

Oil revenue including
oil derivative
settlements               $    7,883             (44 %)    $  14,039      $  14,915            (39 %)    $  24,610
Oil derivative
unrealized gains
(losses)                      (3,034 )           (22 %)       (3,897 )       (4,341 )            5 %        (4,135 )

Oil revenue including
derivative settlements
and unrealized gains
(losses)                  $    4,849             (52 %)    $  10,142      $  10,574            (48 %)    $  20,475
Natural gas revenue:
Natural gas revenue       $    5,104             (78 %)    $  23,231      $  12,963            (70 %)    $  42,584
Natural gas derivative
settlement gains
(losses)                       1,508              NM          (1,756 )        7,947             NM          (1,232 )

Natural gas revenue
including derivative
settlements               $    6,612             (69 %)    $  21,475      $  20,910            (49 %)    $  41,352
Natural gas derivative
unrealized gains
(losses)                        (979 )           (85 %)       (6,653 )       (2,550 )          (78 %)      (11,809 )

Natural gas revenue
including derivative
settlements and
unrealized gains
(losses)                  $    5,633             (62 %)    $  14,822      $  18,360            (38 %)    $  29,543
Oil and natural gas
revenue:
Oil and natural gas
revenue                   $   13,209             (66 %)    $  38,871      $  27,018            (61 %)    $  69,381
Oil and natural gas
derivative settlement
gains (losses)                 1,286              NM          (3,357 )        8,807             NM          (3,419 )

Oil and natural gas
revenue including
derivative settlement
gains (losses)                14,495             (59 %)       35,514         35,825            (46 %)       65,962
Oil and natural gas
derivative unrealized
gains (losses)                (4,013 )           (62 %)      (10,550 )       (6,891 )          (57 %)      (15,944 )

Oil and natural gas
revenue including
derivative settlements
and unrealized gains
(losses)                      10,482             (58 %)       24,964         28,934            (42 %)       50,018
Other revenue                     32             (48 %)           62             66            (16 %)           79

Total revenue             $   10,514             (58 %)    $  25,026      $  29,000            (42 %)    $  50,097

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                                            Three months ended June 30,                    Six months ended June 30,
                                        2009          % Change          2008          2009          % Change          2008

Average oil prices:
Oil price (per Bbl)                  $    49.41             (60 %)    $ 122.22      $   41.63             (62 %)    $ 109.46
Oil price including derivative
settlement gains (losses) (per
Bbl)                                      48.06             (56 %)      109.71          44.18             (56 %)      100.53
Oil price including derivative
settlements and unrealized gains
(losses) (per Bbl)                   $    29.56             (63 %)    $  79.25      $   31.32             (63 %)    $  83.64
Average natural gas prices:
Natural gas price (per Mcf)          $     3.50             (71 %)    $  11.93      $    3.93             (62 %)    $  10.29
Natural gas price including
derivative settlement gains
(losses) (per Mcf)                         4.53             (59 %)       11.03           6.33             (37 %)        9.99
Natural gas price including
derivative settlements and
unrealized gains (losses) (per
Mcf)                                 $     3.86             (49 %)    $   7.61      $    5.56             (22 %)    $   7.14
Average equivalent prices:
Natural gas equivalent price (per
Mcfe)                                $     5.40             (62 %)    $  14.32      $    5.07             (59 %)    $  12.37
Natural gas equivalent price
including derivative settlement
gains (losses) (per Mcfe)                  5.93             (55 %)       13.08           6.72             (43 %)       11.76
Natural gas equivalent price
including derivative settlements
and unrealized gains (losses)
(per Mcfe)                           $     4.29             (53 %)    $   9.19      $    5.43             (39 %)    $   8.92



                                                              For the three              For the six
                                                              month periods             month periods
                                                             ended June 30,        ended June 30, 2009 and
                                                              2009 and 2008                 2008

Change in revenue from the sale of oil
Volume variance impact                                       $         4,410      $                  10,154
Price variance impact                                                (11,945 )                      (22,896 )
Cash settlement of hedging contracts                                   1,379                          3,047
Unrealized hedge gain or loss                                            863                           (206 )

Total change                                                 $        (5,293 )    $                  (9,901 )

Change in revenue from the sale of natural gas
Volume variance impact                                       $        (5,813 )    $                  (8,603 )
Price variance impact                                                (12,314 )                      (21,018 )
Cash settlement of hedging contracts                                   3,264                          9,179
Unrealized hedge gain or loss                                          5,674                          9,259

Total change                                                 $        (9,189 )    $                 (11,183 )

Change in revenue from the sale of oil and natural gas
Volume variance impact                                       $        (1,403 )    $                   1,551
Price variance impact                                                (24,259 )                      (43,914 )
Cash settlement of hedging contracts                                   4,643                         12,226
Unrealized hedge gain or loss                                          6,537                          9,053

Total change                                                 $       (14,482 )    $                 (21,084 )

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Second quarter 2009 oil and natural gas revenues including derivative cash settlements and unrealized gains (losses) decreased $14.5 million when compared to that in the second quarter 2008. The change in revenues was attributable to the following:
• a 62% decrease in pre-hedge per Mcfe sales prices resulted in a $24.3 million decrease in revenues;

• a decrease in natural gas production, which was partially offset by an increase in our oil volumes, resulted in a $1.4 million decrease in oil and natural gas revenues;

• a $1.3 million gain from the settlement of derivative contracts in the second quarter 2009 versus a $3.3 million loss from the settlement of derivative contracts in second quarter 2008 increased revenues by $4.6 million; and

• a $4.0 million unrealized derivative loss in second quarter 2009 versus a $10.5 million unrealized derivative loss in second quarter 2008 increased revenues by $6.5 million.

First six months 2009 oil and natural gas revenues including derivative cash settlements and unrealized gains (losses) decreased $21.0 million when compared to that in the first six months 2008. The change in revenues was attributable to the following:
• a 59% decrease in pre-hedge per Mcfe sales prices resulted in a $43.9 million decrease in revenues;

• an increase in oil production, which was partially offset by a decrease in our natural gas volumes, resulted in a $1.6 million increase in oil and natural gas revenues;

• an $8.8 million gain from the settlement of derivative contracts in the first six months 2009 versus a $3.4 million loss from the settlement of derivative contracts in first six months 2008 increased revenues by $12.2 million; and

• a $6.8 million unrealized derivative loss in first six months 2009 versus a $15.9 million unrealized derivative loss in first six months 2008 increased revenues by $9.1 million.

Hedging. We utilize collars, three way costless collars and swaps to (i) reduce the effect of price volatility on the commodities that we produce and sell,
(ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending plans.

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The following table details derivative contracts that settled during the second quarter and first six months 2009 and 2008 and includes the type of derivative contract, the volume, the weighted average NYMEX reference price for those volumes, and the associated gain (loss) upon settlement.

                         Three months ended June 30,                    Six months ended June 30,
                     2009        % Change          2008            2009         % Change          2008
Oil collars
Volumes (Bbls)        19,000           (60 %)        47,000          49,000           (47 %)        92,500
Average floor
price ($ per
Bbl)               $   59.63           (13 %)   $     68.18     $     71.58            10 %    $     64.98
Average ceiling
price ($ per
Bbl)               $   78.70           (13 %)   $     90.91     $     96.96            10 %    $     88.29
Gain (loss) upon
settlement ($ in
thousands)         $      45            NM      $    (1,601 )   $     1,127            NM      $    (2,187 )

Oil swaps
Volumes (Bbls)        30,000            NM                -          30,000            NM                -
Average swap
price ($ per
Bbl)               $   50.75            NM      $         -     $     50.75            NM      $         -
Gain (loss) upon
settlement ($ in
thousands)         $    (267 )          NM      $         -     $      (267 )          NM      $         -

Total oil
Gain (loss) upon
settlement ($ in
thousands)         $    (222 )         (86 %)   $    (1,601 )   $       860            NM      $    (2,187 )

Natural gas
collars
Volumes (MMbtu)      250,000           (82 %)     1,370,000       1,220,000           (58 %)     2,890,000
Average floor
price ($ per
MMbtu)             $    6.89            (3 %)   $      7.14     $      7.74             3 %    $      7.52
Average ceiling
price ($ per
MMbtu)             $    8.19           (14 %)   $      9.54     $      9.42           (15 %)   $     11.06
Gain (loss) upon
settlement ($ in
thousands)         $     676            NM      $    (1,756 )   $     6,931            NM      $    (1,232 )

Natural gas
swaps
Volumes (MMbtu)      882,000            NM                -       1,062,000            NM                -
Average swap
price ($ per
MMbtu)             $   4.438            NM      $         -     $     4.572            NM      $         -
Gain (loss) upon
settlement ($ in
thousands)         $     832            NM      $         -     $     1,016            NM      $         -

Total gas
Gain (loss) upon
settlement ($ in
thousands)         $   1,508            NM      $    (1,756 )   $     7,947            NM      $    (1,232 )

Other revenue. Other revenue relates to fees that we charge other parties who use our gas gathering systems that we own to move their production from the wellhead to first party gas pipeline systems. Operating costs and expenses
Production costs. We believe that per unit of production measures are the best way to evaluate our production costs. We use this information to internally evaluate our performance, as well as to evaluate our performance relative to our peers.

                                      Unit-of-Production                                  Amount
                                          (Per Mcfe)                                  (In thousands)
                                  Three months ended June 30,                   Three months ended June 30,
                              2009          % Change         2008           2009           % Change         2008

Production costs:
Operating & maintenance     $    1.17              56 %     $  0.75      $    2,853               40 %     $ 2,036
Expensed workovers               0.18              20 %        0.15             445                9 %         410
Ad valorem taxes                 0.11             175 %        0.04             275              170 %         102

Lease operating expenses    $    1.46              55 %     $  0.94      $    3,573               40 %     $ 2,548

Production taxes                 0.34             (36 %)       0.53             831              (42 %)      1,441

Production costs            $    1.80              22 %     $  1.47      $    4,404               10 %     $ 3,989

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Second quarter 2009 per unit of production costs increased $0.33 per Mcfe, or 22%, when compared to that in the second quarter last year mainly due to the following:
• O&M expense increased $0.42 per Mcfe, or 56%, due to an increase in compressor rental and maintenance, electricity, salt water disposal, surface equipment repair and well service and repair; and

• production taxes decreased $0.19 per Mcfe, or 36%, due to lower commodity prices.

                                       Unit-of-Production                                 Amount
                                           (Per Mcfe)                                 (In thousands)
                                   Six months ended June 30,                     Six months ended June 30,
                              2009           % Change         2008          2009          % Change         2008

Production costs:
Operating & maintenance     $    1.07               55 %     $  0.69      $   5,697              48 %     $ 3,858
Expensed workovers               0.21               (5 %)       0.22          1,125              (8 %)      1,224
Ad valorem taxes                 0.10               25 %        0.08            550              22 %         452

Lease operating expenses    $    1.38               39 %     $  0.99      $   7,372              33 %     $ 5,534

Production taxes                 0.31              (37 %)       0.49          1,645             (40 %)      2,724

Production costs            $    1.69               14 %     $  1.48      $   9,017               9 %     $ 8,258

First six months 2009 per unit of production costs increased $0.21 per Mcfe, or 14%, when compared to the first six months last year mainly due to the following:
• O&M expense increased $0.38 per Mcfe, or 55%, due to an increase in compressor rental and maintenance, electricity, and salt water disposal; and

• production taxes decreased $0.18 per Mcfe, or 37%, due to lower commodity prices.

General and administrative expenses. We capitalize a portion of our general and administrative costs. Capitalized costs include the cost of technical employees who work directly on capital projects and a portion of our associated technical organization costs such as supervision, telephone and postage.

                                 Three months ended June 30,                     Six months ended June 30,
. . .