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 nine month periods ended September 30, 2009 and September 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 horizontal drilling, multi-stage isolated fracture stimulation and 3-D seismic imaging, 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 through mid year 2009 have invested a total of $182 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.
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 Third Quarter 2009 Financial Results Third quarter 2009 oil and natural gas prices, excluding realized and unrealized derivative hedging results, decreased 47% and 66%, respectively, from that in the third quarter 2008. In the third quarter 2009, the average sales price that we received for oil, excluding realized and unrealized derivative hedging results, was $59.74 per barrel, which represents a $52.86 per barrel decrease from that in the third quarter 2008. In the third quarter 2009, the average sales price that we received for natural gas, excluding realized and unrealized derivative hedging results, was $3.38 per Mcf, which represents a $6.70 per Mcf decrease from that in the third quarter 2008.
Our third quarter 2009 production averaged 5,200 barrels of oil equivalent per day, which represents a 15% sequential increase from that in the second quarter 2009 and a 13% increase from that in the third quarter 2008. During the third quarter 2009, our oil volumes increased by 84% to approximately 2,606 barrels per day versus that in the third quarter 2008 as a result of our increased activity level in the Williston Basin. The natural production decline from our wells and our decreased level of drilling activity along the Texas Gulf Coast led to reduced natural gas production, which partially offset our higher oil production.
Our third quarter 2009 oil and natural gas revenues, including hedge settlements but excluding unrealized hedging gains and losses, were down $10.6 million, or 36%, compared to that in the third quarter 2008. Oil revenues in the third quarter 2009, including hedge settlements but excluding unrealized hedging gains and losses, increased $0.1 million from that in the third quarter 2008. Higher production volumes and hedge settlements increased oil revenues by $12.0 million and $0.5 million, respectively, while lower oil prices decreased oil revenues by $12.4 million. Natural gas revenues in the third quarter 2009, including hedge settlements but excluding unrealized hedging gains and losses, decreased $10.7 million

compared to that in the third quarter 2008. Lower natural gas prices and reduced production volumes decreased natural gas revenues $9.4 million and $3.2 million, respectively, while higher hedge settlements increased revenues by $1.9 million.
Third quarter 2009 operating income decreased $23.5 million from that in the third quarter last year. This decrease was attributable to the decline in commodity prices and lower natural gas volumes. These items were partially offset by higher oil volumes and lower depletion and general and administrative expenses.
As of September 30, 2009, we had $74.7 million in cash, cash equivalents and investments and $418.8 million in total assets.
Overview of Operational Results - July 1, 2009 to November 5, 2009 Rocky Mountain Province - Williston Basin Recently Completed Wells and Drilling Participation Agreement Strobeck 27-34 #1H. In July 2009, we successfully completed the Strobeck 27-34 #1H, which is a long lateral Three Forks well, with 18 isolated fracture stimulation stages. The Strobeck 27-34 #1H is located in Mountrail County, North Dakota in our Ross project area. The well produced approximately 2,021 barrels of oil equivalent during an early 24 hour flow back. Production from the well over the first 30 days averaged approximately 989 barrels of oil equivalent per day. We own an approximate 77% working interest and a 63% net revenue interest in the Strobeck 27-34 #1H.
Anderson 28-33 #1H. In August 2009, we successfully completed the Anderson 28-33 #1H, which is a long lateral Bakken well with 24 isolated fracture stimulation stages. The Anderson 28-33 #1H is also located in Mountrail County, North Dakota in our Ross project area. The well produced approximately 2,154 barrels of oil equivalent during an early 24 hour flow back. Production from the well over the first 30 days averaged approximately 1,346 barrels of oil equivalent per day. We have an approximate 66% working interest and 54% net revenue interest in the Anderson 28-33 #1H.
Figaro 29-32 #1H. In August 2009, we successfully completed the Figaro 29-32 #1H, which is a long lateral Bakken well, with 19 intervals and 35 pinpoint fracture stimulations. The Figaro 29-32 #1H is located in McKenzie County, North Dakota in our Rough Rider project area. The well produced approximately 1,895 barrels of oil equivalent during an early 24 hour flow back. Production from the well over the first 30 days averaged approximately 831 barrels of oil equivalent per day. We own an approximate 95% working interest and a 75% net revenue interest in the Figaro 29-32 #1H.
Brad Olson 9-16 #1H. In October 2009, we successfully completed the Brad Olson 9-16 #1H, which is a long lateral Bakken well, with 28 isolated fracture stimulation stages. The Brad Olson 9-16 #1H is located in Williams County, North Dakota in our Rough Rider project area. The well produced approximately 2,112 barrels of oil equivalent during an early 24 hour flow back. We have retained an initial approximate 33% working interest and 26% net revenue interest in the well, subject to our Rough Rider drilling participation agreement described below. The Brad Olson 9-16 #1H is the first well to be drilled under our Rough Rider drilling participation agreement.
BCD Farms 16-21 #1H. In November 2009, we successfully completed the BCD Farms 16-21 #1H, which is a long lateral Bakken well, with 28 isolated fracture stimulation stages. The BCD Farms 16-21 #1H is located in Williams County, North Dakota in our Rough Rider project area. The well produced approximately 1,776 barrels of oil equivalent during an early 24 hour flow back. We have retained an initial approximate 24% working interest in the well, subject to our Rough Rider drilling participation agreement described below.
Rough Rider Drilling Participation Agreement. In late August, we entered into a drilling participation agreement in our Rough Rider project area, which encompasses both Williams and McKenzie Counties, North Dakota, in order to accelerate operations and address near term state lease expirations. Initially, six wells are to be drilled under the agreement and our counterparty has the option to participate in an additional nine wells. In each of the initial six wells, we will retain 35% of our original working interest and will back in for 35% of our counterparty's interest in the combined six well group after combined payout (defined as the point in time when the cumulative net receipts from the initial wells equals or exceeds all expenditures for such wells). In the optional nine wells, we may elect to retain 50% to 15% of our original working interest in the wells and back in after payout for a portion of our counterparty's interest. We will have the option to keep up to 64% of our original working interest in all subsequent development wells in the 15 drilling units.

Subsequent Events
Universal Shelf Registration Statement Declared Effective On October 5, 2009, our universal shelf registration statement covering the sale of $300 million of our common stock, preferred stock, depositary shares, warrants, rights, units and debt securities, or any combination of these securities became effective. Following the October equity offering and the exercise by the underwriters of their over-allotment in November, we have $123 million remaining under the shelf registration statement. This shelf registration statement expires in October 2012.
Amendment to Certificate of Incorporation On October 7, 2009, our stockholders approved an amendment to our Certificate of Incorporation to increase the number of shares of common stock which we are authorized to issue from 90 million shares to 180 million shares. The amendment to the Certificate of Incorporation became effective on October 7, 2009.
October 2009 Equity Offering
In October 2009, we completed a public offering of common stock pursuant to our universal shelf registration statement. We sold 16,000,000 shares at a price of $10.50 per share and received net proceeds of $159.9 million, after underwriting fees and offering expenses. We intend to use the proceeds from this offering to fund a portion of our initial 2010 exploration and development budget, which consists primarily of our drilling programs in the Williston Basin that target both the Bakken and Three Forks objectives. Pending use of the net proceeds to fund our exploration and development budget, we used a portion of the net proceeds to repay the outstanding indebtedness under our Senior Credit Facility. We intend to re-borrow under our Senior Credit Facility in 2010 to fund exploration and development costs as they are incurred.
On November 4, 2009, underwriters elected to exercise a portion of the over-allotment option associated with the October 2009 equity offering. This will result in the issuance of 837,523 additional shares from which we will receive net proceeds of approximately $8.4 million when the transaction closes.
2009 and 2010 Capital Budgets
Subsequent to our October equity offering, our 2009 budget is anticipated to remain roughly in line with the budget announced in May 2009, as our lower working interest in wells as a result of our Rough Rider drilling participation agreement offsets the increased number of wells we will drill during the remainder of 2009. We anticipate setting our initial 2010 exploration and development budget at $175.8 million, which would include $169.4 million in drilling and $6.4 million in land capital. The increase in our drilling capital would be used to fund the drilling of 24 net horizontal wells in the Williston Basin. We currently anticipate the 24 net wells would be comprised of 21 net operated wells and three net non-operated wells. The majority of our drilling activity in 2010 would occur in our core developmental acreage positions in our Rough Rider and Ross project areas in Williams, McKenzie and Mountrail Counties, North Dakota. We also anticipate drilling a horizontal Bakken well in our Ghost Rider project area in Roosevelt County, Montana. Finally, our initial 2010 budget currently includes two net wells in our South Texas Vicksburg play in Brooks County, Texas.

Results for the Three and Nine months Ended September 30, 2009 Comparison of the three month and nine month periods ended September 30, 2009 and 2008.

Production volumes

                                    Three months ended September 30,                       Nine months ended September 30,
                                 2009             %Change            2008              2009%             Change            2008
Oil (MBo)                           235               84 %             128                 572               53 %            373
Natural gas (MMcf)                1,401              (19 %)          1,722               4,703              (20 %)         5,861
Total (MBoe)(1)                     468               13 %             415               1,356                1 %          1,349
Average daily production
(Boe/d)(2)                        5,200               13 %           4,611               5,022                1 %          4,996
Average daily production
(MMcfe/d)(2)                       31.2               13 %            27.6                30.1                1 %           30.0

(1) MBoe is defined as one thousand barrels of oil equivalent, determined using the ratio of six MMcf of natural gas to one MBoe of crude oil, condensate or natural gas liquids.

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

Oil represented 50% of our third quarter 2009 production volumes and 42% of our first nine months 2009 production volumes, compared to 31% in the third quarter 2008 and 28% in the first nine months 2008.

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 September 30,                      Nine months ended September 30,
                               2009             %Change            2008             2009             %Change            2008
Oil revenue:
Oil revenue                $     14,010               (3 %)      $ 14,381        $    28,065              (32 %)      $  41,178
Oil derivative
settlement gains
(losses)                           (538 )            (49 %)        (1,050 )              322             NM              (3,237 )

Oil revenue including
derivative
settlements                $     13,472                1 %       $ 13,331        $    28,387              (25 %)      $  37,941
Oil derivative
unrealized gains
(losses)                          1,278              (75 %)         5,055             (3,063 )           NM                 920

Oil revenue including
derivative
settlements and
unrealized gains
(losses)                   $     14,750              (20 %)      $ 18,386        $    25,324              (35 %)      $  38,861
Natural gas revenue:
Natural gas revenue        $      4,737              (73 %)      $ 17,350        $    17,700              (70 %)      $  59,934
Natural gas
derivative settlement
gains (losses)                      798             NM             (1,104 )            8,745             NM              (2,336 )

Natural gas revenue
including derivative
settlements                $      5,535              (66 %)      $ 16,246        $    26,445              (54 %)      $  57,598
Natural gas
derivative unrealized
gains (losses)                     (424 )           NM             12,534             (2,974 )           NM                 725

Natural gas revenue
including derivative
settlements and
unrealized gains
(losses)                   $      5,111              (82 %)      $ 28,780        $    23,471              (60 %)      $  58,323
Oil and natural gas
revenue:
Oil and natural gas
revenue                    $     18,747              (41 %)      $ 31,731        $    45,765              (55 %)      $ 101,112
Oil and natural gas
derivative settlement
gains (losses)                      260             NM             (2,154 )            9,067             NM              (5,573 )

Oil and natural gas
revenue including
derivative
settlements                      19,007              (36 %)        29,577             54,832              (43 %)         95,539
Oil and natural gas
derivative unrealized
gains (losses)                      854              (95 %)        17,589             (6,037 )           NM               1,645

Oil and natural gas
revenue including
derivative
settlements and
unrealized gains
(losses)                         19,861              (58 %)        47,166             48,795              (50 %)         97,184
Other revenue                         6              (76 %)            25                 72              (31 %)            104

Total revenue              $     19,867              (58 %)      $ 47,191        $    48,867              (50 %)      $  97,288

                                   Three months ended September 30,                        Nine months ended September 30,
                               2009             %Change             2008               2009             %Change            2008
Average oil prices:
Oil price (per Bo)           $    59.74              (47 %)        $ 112.60          $    49.06              (56 %)       $ 110.54
Oil price including
derivative settlement
gains (losses) (per
Bo)                               57.45              (45 %)          104.38               49.62              (51 %)         101.85
Oil price including
derivative settlements
and unrealized gains
(losses) (per Bo)            $    62.90              (56 %)        $ 143.96          $    44.27              (58 %)       $ 104.32
Average natural gas
prices:
Natural gas price (per
Mcf)                         $     3.38              (66 %)        $  10.08          $     3.76              (63 %)       $  10.23
Natural gas price
including derivative
settlement gains
(losses) (per Mcf)                 3.95              (58 %)            9.44                5.62              (43 %)           9.83
Natural gas price
including derivative
settlements and
unrealized gains
(losses) (per Mcf)           $     3.65              (78 %)        $  16.72          $     4.99              (50 %)       $   9.95
Average oil equivalent
prices:
Oil equivalent price
(per Boe)                    $    40.06              (48 %)        $  76.46          $    33.75              (55 %)       $  74.95
Oil equivalent price
including derivative
settlement gains
(losses) (per Boe)                40.61              (43 %)           71.27               40.44              (43 %)          70.82
Oil equivalent price
including derivative
settlements and
unrealized gains
(losses) (per Boe)           $    42.44              (63 %)        $ 113.65          $    35.98              (50 %)       $  72.04



                                                                      For the three               For the nine
                                                                      month periods              month periods
                                                                   ended September 30,          ended September
                                                                      2009 and 2008            30, 2009 and 2008
Change in revenue from the sale of oil
Volume variance impact                                            $              12,025        $           22,061
Price variance impact                                                           (12,396 )                 (35,174 )
Cash settlement of hedging contracts                                                512                     3,559
Unrealized hedge gain or loss                                                    (3,777 )                  (3,983 )

Total change                                                      $              (3,636 )      $          (13,537 )

Change in revenue from the sale of natural gas
Volume variance impact                                            $              (3,227 )      $          (11,818 )
Price variance impact                                                            (9,386 )                 (30,416 )
Cash settlement of hedging contracts                                              1,902                    11,081
Unrealized hedge gain or loss                                                   (12,958 )                  (3,699 )

Total change                                                      $             (23,669 )      $          (34,852 )

Change in revenue from the sale of oil and natural gas
Volume variance impact                                            $               8,798        $           10,242
Price variance impact                                                           (21,782 )                 (65,589 )
Cash settlement of hedging contracts                                              2,414                    14,640
Unrealized hedge gain or loss                                                   (16,735 )                  (7,682 )

Total change                                                      $             (27,305 )      $          (48,389 )

Third quarter 2009 oil and natural gas revenues, including derivative cash settlements and unrealized gains (losses), decreased $27.3 million when compared to that in the third quarter 2008. The change in revenues was attributable to the following:
• a 48% decrease in pre-hedge sales prices per Boe resulted in a $21.8 million decrease in revenues;

• a $0.9 million unrealized derivative gain in third quarter 2009 versus a $17.6 million unrealized derivative gain in third quarter 2008 decreased revenues by $16.7 million;

• an increase in oil production, which was partially offset by a decrease in our natural gas volumes, resulted in a $8.8 million increase in oil and natural gas revenues; and

• a $0.3 million gain from the settlement of derivative contracts in the third quarter 2009 versus a $2.1 million loss from the settlement of derivative contracts in third quarter 2008 increased revenues by $2.4 million.

First nine months 2009 oil and natural gas revenues, including derivative cash settlements and unrealized gains (losses), decreased $48.4 million when compared to that in the first nine months 2008. The change in revenues was attributable to the following:
• a 55% decrease in pre-hedge sales prices per Boe resulted in a $65.6 million decrease in revenues;

• a $6.1 million unrealized derivative loss in first nine months 2009 versus a $1.6 million unrealized derivative gain in first nine months 2008 decreased revenues by $7.7 million;

• an increase in oil production, which was partially offset by a decrease in our natural gas volumes, resulted in a $10.2 million increase in oil and natural gas revenues; and

• a $9.0 million gain from the settlement of derivative contracts in the first nine months 2009 versus a $5.6 million loss from the settlement of derivative contracts in first nine months 2008 increased revenues by $14.6 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. The following table details derivative contracts that settled during the third quarter and first nine 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 September 30,                          Nine months ended September 30,
                                  2009             %Change            2008                 2009             %Change            2008
Oil collars
Volumes (Bbls)                     92,000             88 %             49,000              141,000              0 %            141,500
Average floor price
($ per Bo)                   $      56.39            (25 %)       $     74.92          $     61.67            (10 %)       $     68.42
Average ceiling price
($ per Bo)                   $      74.78            (25 %)       $    100.07          $     82.49            (11 %)       $     92.37
Gain (loss) upon
settlement ($ in
thousands)                   $        (11 )          (99 %)       $    (1,050 )        $     1,115            NM           $    (3,237 )

Oil swaps
Volumes (Bbls)                     30,000            NM                     -               60,000            NM                     -
Average swap price
($ per Bo)                   $      50.75            NM           $         -          $     50.75            NM           $         -
Gain (loss) upon
settlement ($ in
thousands)                   $       (527 )          NM           $         -          $      (793 )          NM           $         -

Total oil
Gain (loss) upon
settlement ($ in
thousands)                   $       (538 )          (49 %)       $    (1,050 )        $       322            NM           $    (3,237 )

Natural gas collars
Volumes (MMbtu)                         -            NM             1,130,000            1,000,000            (75 %)         4,020,000
Average floor price
($ per MMbtu)                $          -            NM           $      7.42          $     7.808              4 %        $     7.494
Average ceiling price
($ per MMbtu)                $          -            NM           $      9.95          $     9.321            (13 %)       $    10.751
Gain (loss) upon
settlement ($ in
thousands)                   $          -            NM           $    (1,104 )        $     5,936            NM           $    (2,336 )

Natural gas three ways
Volumes (MMbtu)                         -            NM                     -              220,000            NM                     -
Average floor price
($ per MMbtu)                $          -            NM           $         -          $      7.44            NM           $         -
Average ceiling price
($ per MMbtu)                $          -            NM           $         -          $      9.86            NM           $         -
Average price -
written puts ($ per
MMbtu)                       $          -            NM           $         -          $      4.58            NM           $         -
Gain (loss) upon
settlement ($ in
. . .