Exhibit 99.2

Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Continuing Operations

Year Ended December 31, 2011 Compared to Period Ended December 23, 2010

We completed our Corporate Restructuring on December 23, 2010. The operating results presented below for the audited period ended December 23, 2010 exclude the audited eight-day period from inception through December 31, 2010. The operating results of BCEI for the eight-day period from December 23, 2010 through December 31, 2010 were net revenues, operating expense, and income from operations of approximately $1.6 million, $1.2 million, and $0.4 million, respectively, and did not include transactions that were inconsistent or unusual when compared to the results for the audited period ended December 23, 2010. Other expense during this period was primarily comprised of a $0.5 million unrealized loss in the fair value of commodity derivatives.

Results of Operations

The following discussion is of our consolidated results of operations, financial condition and capital resources. You should read this discussion in conjunction with our Consolidated Financial Statements and the Notes thereto contained elsewhere in this Current Report on Form 8-K. Comparative results of operations for the period indicated are discussed below.

Year Ended December 31, 2011 Compared to Period Ended December 23, 2010

Revenues

(1)                                 Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil. Excludes CO2 sales.

(1)                                 Although we do not designate our derivatives as cash flow hedges for financial statement purposes, the derivatives do economically hedge the price we receive for crude oil and natural gas.

(2)                                 Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil. Excludes CO2 sales.

Revenues increased by 143% to $105.7 million for the year ended December 31, 2011 compared to $43.5 million for the period ended December 23, 2010. Oil production increased 121% and natural gas production increased 112% during the year ended December 31, 2011 as compared to the period ended December 23, 2010. The most significant components of the increased production was related to an increased drilling program and the acquisition of HEC, which occurred on December 23, 2010. Our product revenues and production for the period ended December 23, 2010 excluded HEC revenues and production of $14.0 million and 268.2 Mboe, respectively. The increase in net revenues was also the result of a 22% increase in oil prices with a 2% increase in natural gas prices, respectively, for an overall increase of 19% per Boe. Also contributing to the increased revenue was a 97% increase in production attributable to our drilling program. During 2011, we drilled and completed approximately 100 wells as compared to 42 wells during 2010.

Operating Expenses

Lease operating expenses.  Our lease operating expenses increased $6.3 million, or 53%, to $18.3 million for the year ended December 31, 2011 from $12.0 million for the period ended December 23, 2010 and decreased on an equivalent basis from $16.02 per

Boe to $11.90 per Boe. The increase in lease operating expense was related to increased production volumes due to the acquisition of HEC on December 23, 2010 and increased production attributable to our drilling program. The period ended December 23, 2010 does not include HEC lease operating expenses, which were $2.0 million. During the year ended December 31, 2011, gauging and pumping, compressor rentals, well servicing and testing, and gas plant maintenance and repairs were $1.8 million, $1.0 million, $1.0 million and $0.8 million higher, respectively, than the period ended December 23, 2010. The decrease in lease operating expenses on an equivalent basis was primarily related to the lower operating costs of the wells acquired from HEC. On an equivalent basis, the lease operating expense for the wells acquired from HEC was $7.50 per Boe during the period ended December 23, 2010 as compared to the lease operating expense for BCEC’s wells which was $16.02 per Boe during the period ended December 23, 2010.

Severance and ad valorem taxes.  Our severance and ad valorem taxes increased $4.4 million, or 303%, to $5.9 million for the year ended December 31, 2011 from $1.5 million for the period ended December 23, 2010 and increased on a Boe basis from $1.97 to $3.86. The increase was primarily related to a 106% increase in production volumes and a 19% increase in realized prices per Boe during the year ended December 31, 2011 as compared to the period ended December 23, 2010, and an increase in ad valorem tax of $2.4 million due to higher assessment values. The period ended December 23, 2010 does not include HEC severance and ad valorem tax, which were $0.8 million. The increase in severance and ad valorem taxes on a Boe basis for the year ended December 31, 2011 as compared to the period ended December 23, 2010 was primarily related to higher ad valorem taxes of $2.4 million and true-ups of estimated severance taxes based on Colorado severance tax returns for 2009 and 2010 that were filed during April of the subsequent year. The revision of estimated severance taxes based on the final Colorado severance tax returns resulted in a decrease in severance tax expense in 2010 and an increase in severance tax expense in 2011.

General and administrative.  Our general and administrative expense increased $9.2 million, or 110%, to $17.6 million for the year ended December 31, 2011 from $8.4 million for the period ended December 23, 2010. The period ended December 23, 2010 does not include HEC’s general and administrative expenses, which were $0.6 million. During the year ended December 31, 2011 wages and benefits and legal and professional services fees were $2.1 million and $2.0 million, respectively, higher than the previous period. The increase in wages and benefits is related to increased head count and $1.1 million of the increase in legal and professional services fees were related to investigations and transactions not consummated. In connection with our IPO, the Company distributed 243,945 fully vested shares of common stock previously held in trust to our employees and recorded a $4.1 million stock compensation charge. In addition, the Company distributed the remaining 3,400 shares of our former Class B common stock to our employees. In connection with our IPO, all issued and outstanding shares of our former Class B Common Stock converted into 437,787 shares of restricted common stock, vesting over a three year period and we recorded a $0.1 million stock compensation charge. We expect to recognize employee stock compensation expense relating to these grants during the years ended December 31, 2012, 2013, and 2014 of approximately $2.5 million, $2.5 million, and $2.3 million, respectively, assuming no forfeitures.

Depreciation, depletion and amortization.  Our depreciation, depletion and amortization expense increased $15.4 million, or 122%, to $28.0 million for the year ended December 31, 2011 from $12.6 million for the period ended December 23, 2010. This increase was the result of a 106% increase in production and the step up in basis that was recorded in oil and gas properties as a result of our Corporate Restructuring. In connection with our Corporate Restructuring, all of our oil and gas fields were adjusted to fair value based on each field’s discounted future net cash flows, which resulted in basis increases to the Mid-Continent and Rocky Mountain fields with corresponding decreases to the California fields. Our depreciation, depletion and amortization expense per Boe increased by $1.38, or 8%, to $18.27 for the year ended December 23, 2011 as compared to $16.89 for the period ended December 23, 2010.

Exploration.  Our exploration expense increased $0.7 million, or 286%, to $0.9 million for the year ended December 31, 2011 from $0.2 million in the period ended December 23, 2010. The increase in exploration expense was primarily related to the acquisition of 7,700 acres of 3-D seismic data on the eastern edge of the Wattenberg field in Weld County, Colorado to help evaluate our Niobrara oil shale acreage.

Impairment of Proved Properties.  The Company recorded $0.6 million of proved property impairments in one non-core field in Southern Arkansas for the year ended December 31, 2011. The impairment of the non-core field in Southern Arkansas was related to the loss of a lease. There were no impairments of proved properties for the period ended December 23, 2010.

Other Income and Expense

Interest expense.  Our interest expense decreased $14.0 million, or 78%, to $4.0 million for the year ended December 31, 2011 from $18.0 million for the period ended December 23, 2010. The decrease resulted from the application of $182 million of cash proceeds from our Corporate Restructuring to repay the second lien term loan, the senior subordinated notes and a related party note

payable, and to repay $29 million of principal under our credit facility on December 23, 2010. Average debt outstanding for the year ended December 31, 2011 was $95.3 million as compared to $215.3 million for the period ended December 23, 2010.

Realized gain (loss) on settled commodity derivatives.  Realized gains on oil and gas hedging activities decreased by $8.9 million from a gain of $5.9 million for the period ended December 23, 2010 to a loss of $3.0 million for the year ended December 31, 2011. Because we assumed a derivative in a liability position in 2008, our realized gain was higher by $4.8 million upon the settlement of this portion of the assumed derivative in the period ended December 23, 2010. The decrease from a realized cash hedge gain to a loss period over period was primarily related to commodity prices that were 19% higher during the year ended December 31, 2011 as compared to the period ended December 23, 2010.

Income Tax Expense.  Our predecessor, BCEC, was not subject to federal and state income taxes. As a result of our Corporate Restructuring, we were organized as a Delaware corporation subject to federal and state income taxes. During the year ended December 31, 2011, the estimated effective tax rate was revised to reflect significant capital expenditures in Arkansas and the effective tax rate increased from 36.87% to 37.98%. The increase in the effective tax rate was applied to the January 1, 2011 deferred income tax liability resulting in an increase to the net deferred tax liability and deferred income tax expense of $2.4 million with an additional $10.5 million incurred for federal and state income taxes for the year ended December 31, 2011 for a total deferred income tax expense in our consolidated statement of operations of $12.9 million. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. All income taxes for the year ended December 31, 2011 were deferred.

Change in fair value of warrant put option.  The fair value of the warrant put option decreased $34.3 million, or 100%, to $0 for the year ended December 31, 2011 from a gain of $34.3 million for the period ended December 23, 2010. The decrease resulted from the exercise of the warrants on December 23, 2010 in connection with our Corporate Restructuring.

Amortization of debt discount.  Our expense for amortization of debt discount decreased $8.9 million, or 100%, to $0 for the year ended December 31, 2011 from $8.9 million for the period ended December 23, 2010. The decrease resulted from the retirement of BCEC’s senior subordinated notes on December 23, 2010 in connection with our Corporate Restructuring.

Period Ended December 23, 2010 Compared to Year Ended December 31, 2009

Revenues

(1)                                 Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil. Excludes CO2 sales.

(1)                                 Although we do not designate our derivatives as cash flow hedges for financial statement purposes, the derivatives do economically hedge the price we receive for crude oil and natural gas.

(2)                                 Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil. Excludes CO2 sales.

Product revenues increased by 49%, to $43.5 million in 2010 compared to $29.2 million in 2009. The increase in product revenues was primarily due to higher average prices for oil, natural gas and natural gas liquids in 2010 as compared to 2009 of 34%, 21% and 34%, respectively, and higher natural gas and natural gas liquids production in 2010 as compared to 2009 of 40% and 83%, respectively. Production increases for natural gas and natural gas liquids were due primarily to 2010 development activities on our properties in southern Arkansas and Colorado. During 2010, we drilled 51 net wells as compared to 2.5 net wells drilled in 2009. Furthermore, our McKamie gas plant in Arkansas processed natural gas for HEC in 2009 and 2010 and we recognized natural gas and natural gas liquids volumes and revenues earned under a processing agreement. Natural gas and natural gas liquid volumes and revenues increased as HEC drilled 12 wells in 2010 as compared to 4 wells in 2009. Oil production decreased by 1% in 2010 as compared to 2009 primarily due to low drilling in 2009 and early 2010 resulting in a continued rate of decline for oil production from existing wells, partially offset by increased drilling activity in the later part of 2010.

Operating Expenses

Lease operating expenses.  Our lease operating expenses increased $1.2 million, or 11%, to $11.9 million in 2010 from $10.7 million in 2009. The increase in lease operating expenses was primarily related to higher compression rental costs in our Dorcheat Macedonia field and increased workover activity.

Severance and ad valorem taxes.  Severance and ad valorem taxes per Boe decreased by $1.18, or 37%, to $1.97 for 2010 from $3.15 for 2009. The decrease in production taxes was due primarily to refunds received from Colorado for overpayment of severance taxes in 2008 and 2009.

General and administrative.  Our general and administrative expenses increased $0.8 million, or 10%, to $8.4 million for 2010 from $7.6 million for 2009. The increase in general and administrative expenses was due primarily to an aggregate bonus of $0.5 million awarded to employees in connection with our Corporate Restructuring in December 2010.

Depreciation, depletion and amortization.  Our depreciation, depletion and amortization expense was commensurate with 2009. However, our depreciation, depletion and amortization expense per Boe produced decreased by $0.84, or 7%, to $11.23 for 2010 as compared to $12.07 for 2009 due primarily to additional reserves resulting from higher commodity prices in 2010 and reserves adds from behind-pipe activities.

Cancelled private placement.  During 2010, we incurred expenditures of $2.4 million in connection with our efforts to sell preferred stock through a private placement offering. Cost incurred is comprised primarily of legal fees, printing cost, travel and audit fees. The offering was cancelled in August 2010.

Other Income and Expense

Interest expense.  Our interest expense increased $1.4 million, or 8%, to $18.0 million in 2010 from $16.6 million in 2009. As a result of $30 million in borrowings on a second lien note at a 14% rate, we paid down our first lien revolver at an annual rate of approximately 4%.

Realized gain on settled commodity derivatives.  Our realized gain on settled commodity derivatives decreased $7.6 million, or 56%, to $5.9 million in 2010 from $13.5 million in 2009. The change was primarily related to higher commodity prices during 2010 that lowered our realized gain.

Change in fair value of warrant put option.  The unrealized gain from the change in the fair value of the warrant put option increased $115 million to a gain of $34.3 million for 2010, as compared to a $80.6 million loss for the period ended December 31. 2009. This gain of $34.3 million resulted from a decrease in the value of the warrant put option from $81.5 million as of December 31, 2009 to $47.1 million as of December 23, 2010. The warrant was exercised for Class A units of BCEC and which were subsequently redeemed in exchange for shares of our former Class A Common Stock in connection with our Corporate Restructuring and, therefore, no exercise occurred after December 23, 2010.

Accretion of debt discount.  Our expense for accretion of debt discount increased $0.9 million, or 11%, to $8.9 million for the year ended December 31, 2010. The accretion expense is related to the amortization of the debt discount for BCEC’s Series A, Series B and Series C Senior Subordinated Unsecured Notes.

Results for Discontinued Operations

The Company’s decision to begin marketing, with an intent to sell, all of its oil and gas properties in California during June of 2012 required retrospective revision to the Company’s year-end financial statements that were previously filed in our Annual Report on Form 10-K.  The retrospective revision to reflect the discontinued operations had no impact on net income (loss), total assets or net assets for the years presented.

The operating results before income taxes for our California properties for the year ended December 31, 2011 were net revenues, operating expenses, and loss from discontinued operations of $6.7 million, $10.3 million, and $3.6 million, respectively, as compared to net revenues, gain on the sale of the Jasmin property, operating expenses, and gain from discontinued operations of $4.8 million, $4.1 million, $4.7 million, and $0.1 million for the period ended December 23, 2010.  Operating expenses for the year ended December 31, 2011 included impairments in the amount of $3.4 million.  Sales volumes for the year ended December 31, 2011 and period ended December 23, 201 were 66.1 MBbls and 67.6 MBbls, respectively.

The operating results before income taxes for our California properties for period ended December 23, 2010 were net revenues, gain on the sale of the Jasmin property, operating expenses, and gain from discontinued operations of $4.8 million, $4.1 million, $4.7 million, and $0.1 million, respectively, as compared to net revenues, operating expenses, and loss from discontinued operations of $5.2 million, $5.1 million, and $0.1 million for the year ended December 31, 2009.  Operating expenses for the year ended December 31, 2009 include impairments of $0.6 million.  Sales volumes for the period ended December 23, 2010 and year ended December 31, 2009 were 67.6 MBbls and 102.6 MBbls, respectively.

Liquidity and Capital Resources

We completed our Corporate Restructuring on December 23, 2010. The cash flows presented below for the audited period ended December 23, 2010 exclude the audited eight day period from inception through December 31, 2010. The operating cash flows, investing cash flows, and financing cash flows associated with the eight day period ended December 31, 2011 were $(1.6) million, $(0.8) million, and $—, respectively.

Our primary sources of liquidity to date have been proceeds from our initial public offering, Corporate Restructuring, capital contributions from investors, borrowings under our credit facility and cash flows from operations. Our primary use of capital has been for the acquisition and development of oil and natural gas properties.

On December 15, 2011 the Company sold 10,000,000 shares of our common stock in our IPO at $17.00 per share, less $1.105 per share for underwriting discounts and commissions. Other expenses related to the issuance and distribution of these shares were approximately $3 million.

On March 29, 2011, we entered into a $300 million senior secured revolving credit facility to provide us with additional liquidity and flexibility for capital expenditures. As of December 31, 2011, we had $6.6 million of indebtedness outstanding and $213.4 million of borrowing capacity available under our credit facility. On November 23, 2011, our borrowing base was increased to $220 million. The size of our borrowing base is at the discretion of the lenders under our credit facility and is dependent upon a number of factors, including commodity prices and oil and gas reserve levels. For a summary of the material provisions of our credit facility, see “—Credit facility.”

We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see “Item 7A.—Quantitative and Qualitative Disclosures on Market Risks.”

We actively review acquisition opportunities on an ongoing basis. Our ability to make significant additional acquisitions for cash is dependent on our obtaining additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.

Cash flows provided by operating activities

Net cash provided by operating activities was $57.6 million for the year ended December 31, 2011, compared to $22.8 million provided by operating activities for the period ended December 23, 2010. The increase in operating activities resulted primarily from an increase in revenues, increased production, and increased commodity prices offset by cash utilized in connection

with changes in working capital when comparing the periods. Cash utilized by changes in working capital for the year ended December 31, 2011 was $7.0 million as compared to $5.8 million that was provided by changes in working capital for the comparable period during 2010. Decreases in working capital of $7.0 million for the year ended December 31, 2011 is comprised primarily of increases in accounts receivable of $11.7 million offset by an increase in accounts payables and accrued liabilities (exclusive of capital accruals) of $6.0 million due primarily to timing of accounts payable check distributions. Increases in working capital of $5.8 million during 2010 is due primarily to an increase in trade payables and accrued expenses (exclusive of capital accruals) of $6.5 million, partially offset by an increase in trade receivables of $0.7 million. Net cash provided by operating activities was $11.1 for the year ended December 31, 2009. Cash used by changes in working capital for the year ended December 31, 2009 was $2.8 million.

Cash flows provided by (used in) investing activities

Expenditures for development of oil and natural gas properties and natural gas plants are the primary use of our capital resources. Net cash used in investing activities for the year ended December 31, 2011 was $158.9 million, compared to $32.1 million cash used in investing activities for the period ended December 23, 2010. For the year ended December 31, 2011, net cash used for the development of oil and natural gas properties was $156.9 million including $22.7 million for a natural gas plant and other facilities. For the period ended December 23, 2010, excluding our Corporate Restructuring, net cash used in investing activities was $32.1 million, of which we spent approximately $1.1 million on acquisitions, $34.7 million for the exploration and development of oil and gas properties including $4.0 million for a natural gas plant and other facilities, advanced $3.7 million to fund HEC’s exploration and development program, offset by the receipt of proceeds in the amount of $7.5 million for the sale of the Jasmin field. In connection with our Corporate Restructuring, $59 million in cash along with common stock valued at $21.1 million was used to acquire HEC. For the year ended December 31, 2009, net cash used in investing activities was $7.2 million, of which we spent approximately $0.7 million for the acquisition of oil and gas properties and $6.6 million for the exploration and development of oil and gas properties.

Cash flows provided by (used in) financing activities

Net cash flow provided by financing activities for the year ended December 31, 2011 was $103.4 million primarily related to the sale of common stock, net of offering expenses, in the amount of $155.9 million offset by a net reduction in debt from payments on our credit facility in the amount of $48.8 million. Cash used for deferred financing costs was approximately $2.3 million and we spent $1.4 million to satisfy employee tax withholding requirements related to common stock that was granted during the period. Net cash provided by financing, excluding Corporate Restructuring, was $9.3 million for the period ended December 23, 2010, primarily related to net borrowings in the amount of $12.7 million offset by deferred financing charges in the amount of $3.4 million. Net cash used in financing activities was $5.5 million for the year ended December 31, 2009, primarily the result of making debt payments on our credit facility.

In connection with our Corporate Restructuring, we received net proceeds of approximately $265 million from the sale of shares of our common stock to West Face Capital and to certain clients of AIMCo. Proceeds from this transaction in the amount of $59 million along with common stock valued at $21.1 million was used to acquire HEC, $17.3 million of the proceeds were used for debt extinguishment penalties, and $182 million was used to retire BCEC’s second lien term loan, the senior subordinated notes and a related party note payable, and to make a $29 million principal payment on BCEC’s line of credit.

Credit facility

On March 29, 2011, we entered into a credit agreement providing for a $300 million senior secured revolving credit facility with an initial borrowing base of $130 million with a $5 million subfacility for standby letters of credit. On September 15, 2011, our borrowing base was increased to $180 million with a $15 million sub facility for standby letters of credit. On December 2, 2011, our borrowing base was increased to $220 million with a $15 million subfacility for standby letters of credit.

Our borrowing base under the credit agreement is redetermined semiannually on each April 1 and October 1 and may be redetermined up to one additional time between such scheduled determinations upon our request or upon the request of the required lenders (defined as lenders holding 662/3% of the aggregate commitments). The borrowing base is determined by the value of our oil and gas reserves. The borrowing base is redetermined (i) in the sole discretion of the administrative agent and all of the lenders, (ii) in accordance with their customary internal standards and practices for valuing and redetermining the value of oil and gas properties in connection with reserve based oil and natural gas loan transactions, (iii) in conjunction with the most recent engineering report and other information received by the administrative agent and the lenders relating to our proved reserves and (iv) based upon the estimated value of our proved reserves as determined by the administrative agent and the lenders.

As of December 31, 2011, we had approximately $6.6 million outstanding under our credit facility. As of March 15, 2012, we had approximately $21.6 million outstanding under our credit facility. The credit facility matures on September 15, 2016. Amounts borrowed and repaid under the credit facility may be reborrowed. The credit facility may be used only to finance development of oil and gas properties, for working capital and for other general corporate purposes.

Our obligations under the credit facility are secured by first priority liens on all of our property and assets (whether real, personal, or mixed, tangible or intangible), including our proved reserves and our oil and gas properties (which term is defined to include fee mineral interests, term mineral interests, leases, subleases, farm-outs, royalties, overriding royalties, net profit interests, carried interests, production payments, back in interests and reversionary interests). The facility is guaranteed by us and all of our direct and indirect subsidiaries.

Interest under the credit facility is generally determined by reference to either, at our option:

·                  the London interbank offered rate, or LIBOR, for an elected interest period plus an applicable margin between 1.75% to 2.75%; or

·                  an alternate base rate (being the highest of the administrative agent’s prime rate, the federal funds effective rate plus 0.5% or 3-month LIBOR plus 1.00%) plus an applicable margin between 0.75% and 1.75%.

The applicable margin varies on a daily basis based on the percentage outstanding under the borrowing base. We incur quarterly commitment fees based on the unused amount of the borrowing base ranging from 0.375% and 0.50% per annum. We may prepay loans under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs).

The credit facility contains various covenants limiting our ability to:

·                  grant or assume liens;

·                  incur or assume indebtedness;

·                  grant negative pledges or agree to restrict dividends or distributions from subsidiaries;

·                  sell, transfer, assign or convey assets, or engage in certain mergers or acquisitions;

·                  make certain distributions;

·                  make certain loans, advances and investments;

·                  engage in transactions with affiliates;

·                  enter into sale and leaseback, take-or-pay or hydrocarbon prepayment transactions; or

·                  enter into certain swap agreements.

The credit facility also contains covenants requiring us to maintain:

·                  a current ratio of not less than 1.0 to 1.0; and

·                  a debt to EBITDAX coverage ratio of not more than: 4.00 to 1.00 as of the quarter ending March 31, 2011 (using EBITDAX for the quarter then ended multiplied by four); 4.00 to 1.00 as of the quarter ending June 30, 2011 (using EBITDAX for the two quarters then ending multiplied by two); 4.00 to 1.00 as of the quarter ending September 30, 2011 (using EBITDAX for the three quarters then ending multiplied by 4/3); and 4.00 to 1.00 as of the quarter ending December 31, 2011 and each quarter thereafter (using the trailing four-quarter EBITDAX).

As of December 31, 2011, we were in compliance with these ratios. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the loan and exercise other rights and remedies.

The credit agreement contains customary events of default, including:

·                  failure to pay any principal, interest, fees, expenses or other amounts when due;

·                  the failure of any representation or warranty to be materially true and correct when made;

·                  failure to observe any agreement, obligation or covenant in the credit agreement, subject to cure periods for certain failures;

·                  a cross-default for the payment of any other indebtedness of at least $2 million;

·                  bankruptcy or insolvency;

·                  judgments against us or our subsidiaries, in excess of $2 million, that are not stayed;

·                  certain ERISA events involving us or our subsidiaries; and

·                  a change in control (as defined in the credit agreement), including the ownership by a “person” or “group” (as defined under the Securities and Exchange Act of 1934, as amended, but excluding certain permitted stockholders) directly or indirectly, of more than 35% of our common stock, other than certain of our current stockholders.

Contractual Obligations

We have the following contractual obligations and commitments as of December 31, 2011 (in thousands):

(1)                                 Amount excludes interest on our credit facility as both the amount borrowed and the applicable interest rate is variable. On March 29, 2011, we entered into a new credit agreement, which matures on September 15, 2016.

(2)                                 See Note 7 to our consolidated financial statements for a description of operating leases.

(3)                                 Amount represents our estimate of future retirement obligations on a discounted basis unless otherwise noted. Because these costs typically extend many years into the future, management prepares estimates and makes judgments that are subject to future revisions based upon numerous factors. The $0.4 million included in the one year or less category is not discounted and is included in accounts payable and accrued expenses as of December 31, 2011.

Critical accounting policies and estimates

The 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 our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 to our audited consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

Method of accounting for oil and natural gas properties

Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively.

Costs of retired, sold or abandoned properties that constitute a part of an amortization base (partial field) are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate for an entire field, in which case a gain or loss is recognized currently. Gains or losses from the disposal of properties are recognized currently.

Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their

estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.

Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as impairment expense in the statement of operations in our consolidated financial statements. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

Oil and natural gas reserve quantities and Standardized Measure

Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the SEC has recently adopted rules which allow us to disclose proved, probable and possible reserves, we have elected to disclose only proved reserves in this Current Report on Form 8-K. The SEC’s revised rules define proved reserves as the quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Our independent engineers and technical staff must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates are updated annually and consider recent production levels and other technical information about each field. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

Revenue recognition

Revenue from our interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership, and collectability is reasonably assured. Substantially all of our production is sold to purchasers under short-term (less than 12 month) contracts at market-based prices. The sales prices for oil and natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment.

Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, we sell the majority of production soon after it is produced at various locations. As a result, we maintain a minimum amount of product inventory in storage.

Impairment of proved properties

We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and natural gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value

are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.

Impairment of unproved properties

We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage and record impairment expense for any decline in value.

We have historically recognized impairment expense for unproved properties at the time when the lease term has expired or sooner if, in management’s judgment, the unproved properties have lost some or all of their carrying value. We consider the following factors in our assessment of the impairment of unproved properties:

·                  the remaining amount of unexpired term under our leases;

·                  our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that may be closer to expiration;

·                  our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;

·                  our ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and

·                  our evaluation of the continuing successful results from the application of completion technology in the Niobrara formation by us or by other operators in areas adjacent to or near our unproved properties.

The assessment of unproved properties to determine any possible impairment requires significant judgment.

Asset retirement obligations

We record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The asset retirement obligation, or ARO, represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized cost is depreciated on the unit-of-production method. The accretion expense is recorded as a component of Depreciation, depletion and amortization in our Consolidated Statement of Operations.

We determine the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Derivatives

We record all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. We have not designated any derivative instruments as hedges for accounting purposes and we do not enter into such instruments for speculative trading purposes. Realized gains and realized losses from the settlement of commodity derivative instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled commodity derivative instruments are reported under Other Income (Expense) in our Consolidated Statement of Operations.

Stock-based compensation

Restricted Stock Awards.  We recognize compensation expense for all restricted stock awards made to employees and directors. Stock-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the requisite service period, which is generally the vesting period. The fair value of restricted stock grants is based on the value of our common stock on the date of grant. Assumptions regarding forfeiture rates are subject to change. Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense recognized. Stock-based compensation expense recorded for restricted stock awards is included in General and administrative expenses on our Consolidated Statement of Operations.

Income taxes

Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.

We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. We did not have any uncertain tax positions as of the year ended December 31, 2011.

Recent accounting pronouncements

Goodwill.  In December 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2010-28, “Intangibles—Goodwill and Other: When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts” (“ASU 2010-28”). ASU 2010-28 requires step two of the goodwill impairment test to be performed when the carrying value of a reporting unit is zero or negative, if it is more likely than not that a goodwill impairment exists. The requirements of this update are effective for fiscal years beginning after December 15, 2010. The adoption of this new guidance did not have an impact on our financial position, cash flows or results of operations.

Business combinations.  In December 2010, the FASB issued ASU 2010-29, “Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations” (“ASU 2010-29”). ASU 2010-29 clarifies that when presenting comparative pro forma financial statements in conjunction with business combination disclosures, revenue and earnings of the combined entity should be presented as though the business combination that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period. In addition, the update requires a description of the nature and amount of material, nonrecurring pro forma adjustments included in pro forma revenue and earnings that are directly attributable to the business combination. This update is effective prospectively for business combinations that occur on or after the beginning of the first annual reporting period after December 15, 2010. As ASU 2010-29 relates to disclosure requirements, there was no impact on our financial position, cash flows or results of operations.

Financial receivables.  On July 21, 2010, the FASB issued ASU 2010-20 “Receivables (Topic 310)—Disclosures about the Credit Quality of Financial Receivables and the Allowance for Credit Losses.” This new ASU requires disclosure of additional information to assist financial statement users to understand more clearly an entity’s credit risk exposures to finance receivables and the related allowance for credit losses. This ASU is effective for all public companies for interim and annual reporting periods ending on or after December 15, 2010 with specific items, such as the allowance rollforward and modification disclosures, effective for

periods beginning after December 15, 2010. The adoption of this new guidance did not have an impact on our financial position, cash flows or results of operations, but appropriate disclosures have been made in our consolidated financial statements.

Fair value.  In January 2010, the FASB issued authoritative guidance to update certain disclosure requirements and added two new disclosure requirements related to fair value measurements. The guidance requires a gross presentation of activities within the Level 3 roll forward and adds a new requirement to disclose details of significant transfers in and out of Level 1 and 2 measurements and the reasons for the transfers. The new disclosures are required for all companies that are required to provide disclosures about recurring and nonrecurring fair value measurements, and is effective the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. The adoption of this new guidance did not have an impact on our financial position, cash flows or results of operations, but appropriate disclosures have been made in our consolidated financial statements.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the periods ended December 31, 2011, 2010 and 2009. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

Off-balance sheet arrangements

Currently, we do not have any off-balance sheet arrangements.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risks.

Oil and Natural Gas Prices.  Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil, the global supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse affect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources. If oil prices decline by $10.00 per Bbl, then our PV-10 as of December 31, 2011 would have been lower by approximately $129.4 million.

Our primary commodity risk management objective is to reduce volatility in our cash flows. Management makes recommendations on hedging that are approved by the board of directors before implementation. We enter into hedges for oil and natural gas using NYMEX futures or over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by our board of directors.

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments, or (2) our counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in such prices.

Presently, all of our hedging arrangements are concentrated with three counterparties, one of which is a lender under our credit facility. If this counterparty fails to perform its obligations, we may suffer financial loss or be prevented from realizing the benefits of favorable price changes in the physical market.

The result of oil market prices exceeding our swap prices or collar ceilings requires us to make payment for the settlement of our hedge derivatives, if owed by us, generally up to three business days before we receive market price cash payments from our

customers. This could have a material adverse effect on our cash flows for the period between hedge settlement and payment for revenues earned.

The following table provides a summary of derivative contracts as of February 29, 2012:

Interest Rates.  At February 29, 2012 we had $16.6 million outstanding under our credit facility, which is subject to floating market rates of interest. Borrowings under our credit facility bear interest at a fluctuating rate that is tied to an adjusted base rate or LIBOR, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow. Based on borrowings outstanding at February 29,2012, a 100 basis point change in interest rates would change our annualized interest expense by approximately $0.2 million.

Counterparty and customer credit risk.  In connection with our hedging activity, we have exposure to financial institutions in the form of derivative transactions. The lenders under our credit facility are currently the counterparties on our derivative instruments currently in place and have investment grade credit ratings. We expect that any future derivative transactions we enter into will be with these or other lenders under our credit facility that will carry an investment grade credit rating.

We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. See “Item 1. Business—Principal Customers” for further detail about our significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history and financial resources of our customers, but we do not require our customers to post collateral.

The marketability of our production from the Mid-Continent, Rocky Mountain and California regions depends in part upon the availability, proximity and capacity of third-party refineries, natural gas gathering systems and processing facilities. We deliver crude oil and natural gas produced from these areas through trucking services and pipelines that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.

A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.

Currently, there are no natural gas pipeline systems that service wells in the North Park Basin, which is prospective for the Niobrara oil shale. In addition, we are not aware of any plans to construct a facility necessary to process natural gas produced from this basin. If neither we nor a third party constructs the required pipeline system and processing facility, we may not be able to fully develop our resources in the North Park Basin.