This discussion and analysis should be read in conjunction with the accompanying financial statements and related notes. Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of any contingent liabilities at the financial statement date and reported amounts of revenue and expenses during the reporting period. On an ongoing basis, we review our estimates and assumptions. Our estimates are based on our historical experience and other assumptions that we believe to be reasonable under the circumstances. Actual results are likely to differ from those estimates under different assumptions or conditions, but we do not believe such differences will materially affect our financial position or results of operations.
Our critical accounting policies (the policies we believe are most important to the presentation of our financial statements and require the most difficult, subjective and complex judgments) are outlined in our notes to financial statements.
This quarterly report contains forward-looking statements. For this purpose, any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. These statements relate to future events or to our future financial performance. In some cases, you can identify forward-looking statements by terminology such as "may," "should," "expects," "plans," "anticipates," "believes," "estimates," "predicts," "potential" or "continue" or the negative of such terms or other comparable terminology. Actual events or results may differ materially from those anticipated or implied in the forward-looking statements. There are a number of risks and uncertainties that could cause our actual results to differ materially from those indicated by such forward-looking statements. These risks and uncertainties include, but are not limited to, those described in this report, in Part II, "Item 1A. Risk Factors," those described in our Annual Report on Form 10-K/A for the year ended December 31, 2008, and those described from time to time in our future reports filed with the SEC.

Overview
We are an independent oil and gas exploration and production company, engaged in the exploration, development, acquisition and production of crude oil and natural gas in the western United States. Our current operations are focused primarily in four main project areas that we call Fetter, Goliath, Krejci and Bigfoot. The following project updates should be read in conjunction with our Annual Report on Form 10-K/A for our fiscal year ended December 31, 2008. Fetter Project (Powder River Basin, Wyoming) Our Fetter project, located in the southern Powder River Basin of Wyoming, currently encompasses approximately 52,000 gross acres. We own a 69.375% working interest in approximately 49,000 net acres, giving us approximately 34,000 total net acres at Fetter. Red Technology Alliance, LLC ("RTA") owns a 25% working interest and North Finn LLC retains the remaining 5.625% working interest. The drilling and completion operations have been project managed by Halliburton Energy Services, Inc.
We continue to progress toward establishing a commercially successful drilling program within our Fetter project area. Currently, our activities include a re-entry program that could enable us to establish production from formations in addition to the primary Frontier formation. We have identified up to five wells that we will focus on in these efforts. Our plans are to re-enter these wells to set a removable bridge plug above the Frontier formation and complete and fracture stimulate the Niobrara formation. After production testing of only the Niobrara formation, we expect to remove the temporary bridge plug and flow the wells from both the Niobrara and Frontier formations. Preparations for the first well re-completion are underway and we expect this re-entry program could take three to six months.
During the third quarter, 2009 we signed an agreement with Halliburton Energy Services, Inc, whereby Halliburton has agreed to pay all costs related to perforating and fracture stimulating the Niobrara formation in up to five existing wells in the field. Pursuant to the agreement, Halliburton will receive 80% of the net revenues from Niobrara production in these wells until the wells cumulatively have paid back a maximum of 200% of the total costs. We retain our proportionate share of the remaining 20% of the net revenue from Niobrara production on the subject wells during the pay back period. Once the payback threshold has been achieved, Halliburton's net revenue interest in the wells will revert back to us and other existing working interest owners at Fetter. This agreement is specific to the five candidate wells. We retain our existing 69.375% working interest in all future wells and formations in the remaining Fetter field net acreage position.
We continue to experience a general decrease in service costs and believe that by (i) combining lower costs to drill and complete wells, (ii) commingling production from multiple formations and (iii) enhancing existing production with artificial lift methods, the Fetter project could provide commercially successful production which will support further development, even in a low natural gas commodity price environment.
Goliath Bakken and Three Forks Project (Williston Basin, North Dakota) Our Goliath project is located primarily in Williams and Dunn Counties, North Dakota in an area where we are targeting both the middle member of the Bakken and Three Forks formations in the North Dakota portion of the Williston Basin. In late June and mid-July 2009, we increased our working interest in the approximate 87,000 gross acre Goliath project from a 50% working interest to a 95% working interest in approximately 63,000 lease net acres.
On June 30, 2009, we purchased approximately 14,900 net undeveloped acres, a 25% ownership in the Champion 1-25H well, a 17% ownership in the Viall 1-30 well, a 6% ownership in the Solberg 32-2 well, and interests in seven gross (approximately .12 net) producing Bakken wells for $900,000 in cash. On July 15, 2009, we closed on an acreage exchange at Goliath which resulted in our receiving approximately 11,600 net acres in return for our 50% working interest in the Champion 1-25H well, our 34% working interest in the Viall 1-30 well, our 11.9% working interest in the Solberg 32-2 well and our rights to formations below the Three Forks in four 640 acre sections.

After closing these transactions, we controlled approximately 60,000 net undeveloped acres at Goliath, a 25% working interest in the Champion 1-25H well, a 17% working interest in the Viall 1-30 well, a 6% working interest in the Solberg 32-2 well and an interest in seven gross (approximately .36 net) other producing Bakken wells.
In October 2009, we signed a purchase agreement to acquire an additional approximate 16,000 net acres in Williams County, North Dakota. This project area acreage, which we call "Titan," is located directly north of and adjacent to our Goliath project area. We have closed on approximately 9,900 net acres and expect to close on the remaining 6,200 net acres within 30 days. With the addition of this acreage position, we would control approximately 76,000 net acres targeting the Bakken and Three Forks formations.
Krejci Oil Project (Powder River Basin, Wyoming) Within our Krejci project, we have been and continue to primarily evaluate the productive potential of the Mowry formation at an approximate depth of 7,500 feet. We have focused our efforts in and around the Krejci Field in Niobrara County, Wyoming. Our Krejci project area currently encompasses approximately 128,000 gross (approximately 52,000 net) acres. In addition to the productive potential of the Mowry formation, there are multiple other formations that are productive in different areas in the middle and southern Powder River Basin, and we continue to evaluate our Krejci acreage position for production potential from these other formations.
Other companies are now either drilling or planning to drill wells targeting the Mowry formation in the middle and southern parts of the Powder River Basin, and we will be evaluating the level of success these other companies have with their drilling, stimulation and completion operations. We do not expect to incur significant capital expenditures in the Krejci project unless or until other companies are successful in establishing commercial production from the Mowry formation.
Bigfoot Project (Rocky Mountain Region)
We currently control approximately 157,000 net acres in a project that we call Bigfoot. This is a shallow natural gas project located in the Rocky Mountain region. We are primarily targeting a formation that is less that 2,000' deep and have drilled a series of test wells for less than $100,000 per well. We expect to continue to drill test wells as we evaluate the commercial viability of the area.
Results of Operations
The following discussion should be read in conjunction with the audited financial statements and notes thereto included in our Annual Report on Form 10-K/A for the fiscal year ended December 31, 2008. It also should be read in conjunction with the financial statements and notes thereto included in this report.
The Quarter Ended September 30, 2009 Compared with the Quarter Ended September 30, 2008
For the quarter ended September 30, 2009, we recorded a net loss attributable to common stockholders of $3,400,573 ($0.07 loss per common share, basic and diluted), as compared to a net loss attributable to common stockholders of $12,780,287 ($0.27 loss per common share, basic and diluted) for the quarter ended September 30, 2008. The $9,379,714 decrease in loss reflects a $16,990,000 decrease in impairment of oil and gas properties, less a $6,520,000 decrease in reduction of deferred income taxes.

For the quarter ended September 30, 2009, we recorded total oil and gas revenues of $462,553 compared with $1,159,621 for the quarter ended September 30, 2008. The $697,068 decrease from the 2008 quarter is substantially attributable to lower oil and gas prices. Oil and gas sales and production costs are summarized in the following table:

                                                            Three months ended
                                                              September 30,
                                                          2009             2008
  Oil sold (barrels)                                         4,877             5,609
  Average oil price                                   $      59.17     $      108.83

  Oil revenue                                         $    288,567     $     610,437


  Gas sold (mcf)                                            49,949            53,783
  Average gas price                                   $       3.48     $       10.21

  Gas revenue                                         $    173,986     $     549,184


  Total oil and gas revenues                          $    462,553     $   1,159,621
  Less lease operating expenses                           (278,429 )        (475,382 )
  Less oil & gas amortization expense                     (212,001 )        (337,000 )
  Less impairment of oil and gas properties             (1,850,000 )     (18,840,000 )
  Less accretion of asset retirement obligation             (9,837 )          (8,427 )
  Less impairment of materials & supplies inventory       (409,852 )               -

  Producing revenues less direct expenses               (2,297,566 )     (18,501,188 )
  Less depreciation of office facilities                   (19,416 )         (19,021 )
  Less amortization of other intangible asset              (45,000 )         (45,000 )
  Less general and administrative expenses              (1,198,188 )        (768,780 )

  Loss from operations                                $ (3,560,170 )   $ (19,333,989 )


  Total barrels of oil equivalent ("boe") sold              13,202            14,573
  Revenue per boe sold                                $      35.04     $       79.57
  Lease operating expense per boe sold                $      21.09     $       32.62
  Amortization expense per boe sold                   $      16.06     $       23.13

Portions of our natural gas production are sent to gas processing plants to profitably extract from the gas various natural gas liquids ("NGL") that are sold separately from the remaining natural gas. We sell some of our processed gas before processing and some after processing but in both cases receive revenues based on a share of post-processing proceeds from plant sales of the extracted NGL and the remaining natural gas. In the table above, our share of processing costs are classified in lease operating expenses, and our share of NGL revenues are included in gas revenues.
For the quarters ended September 30, 2009 and September 30, 2008, we incurred $1,198,188 and $768,780, respectively, in general and administrative expenses. The $429,408 increase is largely attributable to the following in the 2009 period: (i) $78,562 in increased share-based compensation, (ii) approximately $140,000 in increased various other personnel costs, (iii) a $60,000 reduction in land department costs capitalized, (iv) approximately $48,000 in increased rent for additional office space, and (v), in September 2009, approximately $69,000 in bad debt expense.
The Nine-month Period ended September 30, 2009 Compared with the Nine-month Period ended September 30, 2008
We recorded net loss attributable to common stockholders of $8,892,054 ($0.18 loss per common share, basic and diluted) for the nine-month period ended September 30, 2009, as compared to net loss attributable to common stockholders of $15,045,806 ($0.32 loss per common share, basic and diluted) for the nine-month period ended September 30, 2008. The approximately $6.2 million decrease in loss is largely attributable to (i) a $14,890,000 favorable change (before tax effects) in impairment of oil and gas properties, (ii) a $7,500,000 net unfavorable change in deferred income tax expense and (iii) a $982 ,446 increase in general and administrative expenses. Various other significant, but offsetting, changes occurred as shown in the table below.

For the nine months ended September 30, 2009, we recorded total oil and gas revenues of $1,285,705 compared with $2,604,786 for the nine months ended September 30, 2008. The $1,319,081 decrease from the nine months ended September 30, 2008, is attributable to significantly lower oil and gas prices in the 2009 period, as shown in the table below:

                                                            Nine months ended
                                                              September 30,
                                                          2009             2008
  Oil sold (barrels)                                        14,056            13,503
  Average oil price                                   $      46.87     $      104.97

  Oil revenue                                         $    658,759     $   1,417,403


  Gas sold (mcf)                                           183,386           117,711
  Average gas price                                   $       3.42     $       10.09

  Gas revenue                                         $    626,946     $   1,187,383


  Total oil and gas revenues                          $  1,285,705     $   2,604,786
  Less lease operating expenses                           (848,354 )      (1,025,987 )
  Less oil & gas amortization expense                     (546,000 )      (1,047,000 )
  Less impairment of oil and gas assets                 (3,950,000 )     (18,840,000 )
  Less accretion of asset retirement obligation            (30,057 )         (24,759 )
  Less impairment of materials & supplies inventory       (565,991 )               -

  Producing revenues less direct expenses               (4,654,697 )     (18,332,960 )
  Less depreciation of office facilities                   (57,732 )         (56,612 )
  Less amortization of other intangible asset             (135,000 )        (135,000 )
  Less general and administrative expenses              (4,242,539 )      (3,260,093 )

  Loss from operations                                $ (9,089,968 )     (21,784,665 )


  Total barrels of oil equivalent ("boe") sold              44,620            33,122
  Revenue per boe sold                                $      28.81     $       78.64
  Lease operating expense per boe sold                $      19.01     $       30.98
  Amortization expense per boe sold                   $      12.24     $       31.61

Portions of our natural gas production are sent to gas processing plants to profitably extract from the gas various natural gas liquids ("NGL") that are sold separately from the remaining natural gas. We sell some of our processed gas before processing and some after processing but in both cases receive revenues based on a share of post-processing proceeds from plant sales of the extracted NGL and the remaining natural gas. In the table above, our share of processing costs are classified in lease operating expenses, and our share of NGL revenues are included in gas revenues.
General and administrative expenses for the nine months ended September 30, 2009 increased $982,446 (30%) over the same nine-month period in 2008 due primarily to the following in the 2009 period: (i) approximately $500,000 of costs relating to third-party financial advisory services, (ii) approximately $160,117 in increased share-based compensation and (iii) approximately $475,000 in increased various other personnel costs.
We incurred no federal and state income tax liabilities for the nine-month period ended September 30, 2008, but recognized in the three months ended December 31, 2008 current federal income tax expense of $240,000 relating to (a) $26.5 million in taxable gain on sales of certain unproved oil and gas properties (primarily in October 2008) and (b) tax planning at the time to capitalize for our 2008 federal income tax return approximately $11.5 million in intangible drilling costs so as to utilize our net operating loss carryforward and our percentage depletion carryforward, as more fully explained on page F-19 of our Form 10-K/A filed for the year ended December 31, 2008. We ultimately decided to expense for the 2008 federal income tax return filed in September 2009 all intangible drilling costs incurred in 2008 except for capitalization of approximately $800,000, whereby our federal income taxes for 2008 were $90,035 of Alternative Minimum Tax. The $149,965 reduction in income taxes for 2008 is recognized as a $149,965 income tax benefit in the three months ended September 30, 2009. We expect to incur nominal or no income tax liabilities for the remainder of 2009.

Liquidity and Capital Resources
At September 30, 2009 and December 31, 2008, we had working capital of $16.6 million and $26.9 million, respectively. We had cash and cash equivalents at September 30, 2009 of $13.0 million.
We do not expect significant capital or cash requirements for expenditures in the three-month period ending December 31, 2009. We currently anticipate that net cash used by operations and investing activities in the three months ending December 31, 2009, will be less than $2 million. With regards to the proved undeveloped reserves discussed in Note 9 of the financial statements included in this Form 10-Q report, we anticipate spending the estimated $1.2 million of development costs in early 2010.
For the nine-month periods ended September 30, 2009 and September 30, 2008, our sources and uses of cash were as follows:
Net Cash Used By Operating Activities - Our net cash used by operating activities increased by $1,938,797, (from $1,118,277 during the nine months ended September 30, 2008, to $3,057,074 for the nine months ended September 30, 2009). The increase in cash usage was due primarily to the previously mentioned $1,319,081 decrease in oil and gas revenues and an $822,329 increase in general and administrative expenses (other than $160,117 in increased share-based compensation) for the nine-month period in 2009 compared to that in 2008. Net Cash Used In Investing Activities - During the nine months ended September 30, 2009, we used a net $7.2 million in investing activities as compared with $1.6 million cash provided in the nine months ended September 30, 2008. The approximately $8.8 million increase in usage of cash is primarily because the $2.6 million of cash provided by redemptions of ARPS for the 2009 period were $8.85 million less than the 2008 period's $11.45 million of cash provided by redemptions of ARPS and other securities. At the beginning of the 2009 period, we had $20.8 million more in cash and cash equivalents than we had at the beginning of the 2008 period as a source for funding investment activities.
Net Cash Provided By Financing Activities - For the nine months ended September 30, 2009, we had significant cash assets and received no cash provided by financing activities. In March 2008, we received $8,600,000 from a short-term loan in March 2008 when we were unable to liquidate ARPS at par value. We repaid the loan with ARPS redemptions in May and September 2008. In September 2008, we borrowed an additional $2,325,000, which we repaid in November of 2008. FASB Codification Discussion
We follow accounting standards set by the U.S. Financial Accounting Standards Board, commonly referred to as the "FASB." The FASB sets generally accepted accounting principles (GAAP) that we follow in preparing our financial statements of financial condition, results of operations, and cash flows. Over the years, the FASB and other designated GAAP-setting bodies, have issued standards in the form of FASB Statements, Interpretations, FASB Staff Positions, EITF consensuses, AICPA Statements of Position and other documents. The FASB recognized the complexity of its standard-setting process and embarked on a revised process in 2004 that culminated in the release on July 1, 2009, of the FASB Accounting Standards Codification,™ sometimes referred to as the Codification or ASC. The Codification does not change how we account for our transactions or the nature of related disclosures made. However, when referring to guidance issued by the FASB, we refer now to topics in the ASC rather than FASB Statements and other standards superseded by the ASC. The above change was made effective by the FASB for periods ending on or after September 15, 2009.