Exhibit 99.3

Item 8.    Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Bonanza Creek Energy, Inc.

We have audited the accompanying consolidated balance sheets of Bonanza Creek Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year ended December 31, 2011 and the period from its inception (December 23, 2010) to December 31, 2010, and the Bonanza Creek Energy Company, LLC and subsidiaries (predecessor) consolidated statements of operations, members’ equity, and cash flows for the period January 1, 2010 to December 23, 2010 and the year ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Bonanza Creek Energy, Inc. and subsidiaries and its predecessor as of December 31, 2011 and 2010, and the results of their operations and their cash flows for the year ended December 31, 2011, the periods December 23, 2010 to December 31, 2010 and January 1, 2010 to December 23, 2010, and the year ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 13, the Company adopted a plan in 2012 to dispose of certain assets.  The accompanying consolidated financial statements have been reclassified to reflect these assets as held for sale as of December 31, 2011 and 2010, and to reflect the results of the operations of the assets held for sale as discontinued operations for all periods presented.

Hein & Associates LLP

Denver, Colorado

March 22, 2012, except for the third paragraph of Note 13, which is dated January 28, 2013

BONANZA CREEK ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR

CONSOLIDATED STATEMENT OF OPERATIONS

*                                         Bonanza Creek Energy Company, LLC was a limited liability company. See note 1 to Bonanza Creek Energy, Inc.’s annual financial statements.

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

FOR THE PERIOD FROM INCEPTION (DECEMBER 23, 2010) TO DECEMBER 31, 2011

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES AND PREDECESSOR CONSOLIDATED

STATEMENT OF CASH FLOWS

Bonanza Creek Energy, Inc.

Notes to the Consolidated Financial Statements as of December 31, 2011

1. ORGANIZATION AND BUSINESS:

On December 23, 2010, Bonanza Creek Energy, Inc., a Delaware Subchapter C corporation formed on December 2, 2010 (the “Company” or “BCEI”) participated in following transactions which were accomplished simultaneously:

(1)                                 The contribution by Bonanza Creek Energy Company, LLC (“BCEC”) of all of its ownership in Bonanza Creek Energy Operating Company, LLC (a wholly owned subsidiary) to BCEI and the assumption by BCEI of BCEC’s remaining debt (as described below) in exchange for a 21.55% ownership interest of BCEI. BCEC had no other significant assets or subsidiaries at such time. BCEC was an operating oil and gas company that was initially founded in 2006;

(2)                                 The sale of $265 million of Class A common stock of BCEI which constituted an ownership interest of 72.68% of BCEI to Project Black Bear LP (“Black Bear”), an entity advised by West Face Capital Inc. (“West Face Capital”), and to certain clients of Alberta Investment Management Corporation (“AIMCo”); and

(3)                                 The exchange of shares of 5.77% of BCEI’s Class A common stock together with $59 million in cash (which came from the $265 million sale of common stock of BCEI described in (2) above), for all of the equity interests of Holmes Eastern Company, LLC, a Delaware limited liability company (“HEC”), that was majority owned by a minority member of Bonanza Creek Oil Company, LLC (“BCOC”). BCOC was the predecessor of BCEC and owned 29.9% of BCEC on a fully diluted basis at the time of such transaction. HEC was initially formed in 2009 and has been an operating oil and gas exploration and production business since its formation.

The BCEC ownership (21.55%) of BCEI was subsequently distributed to or for the benefit of BCEC’s members based on management’s estimate of fair value of the BCEI shares received by BCEC to holders of the equity interests of BCEC in connection with the redemption of BCEC’s equity and BCEC’s dissolution to or for the benefit of:

(1)                                 BCOC in the amount of 5.5% (for its Class A Units of BCEC);

(2)                                 D.E. Shaw Laminar Portfolios, L.L.C. (“Laminar”) in the amount of 12.91% (for its Class A Units of BCEC); and

(3)                                 The management and employees of BCEC, in the amount of 3.14% (for their Class B Units of BCEC).

Cash proceeds of approximately $182 million were used to retire BCEC’s second lien term loan, senior subordinated notes and a related party note payable, and to reduce the outstanding principal balance on BCEC’s bank revolving credit facility by $29 million thereby reducing the balance outstanding to approximately $55.4 million as of December 31, 2010. This loan at the same time was assumed by BCEI.

The Company is engaged primarily in acquiring, developing, exploiting and producing oil and gas properties. As of December 31, 2011, the Company’s assets and operations are concentrated primarily in southern Arkansas and in the Denver Julesburg and North Park Basins in the Rocky Mountains.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Principles of Consolidation—The consolidated balance sheet includes the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Bonanza Creek Energy Resources Company, LLC and HEC. All significant intercompany accounts and transactions have been eliminated.

Fair Value of Financial Instruments—The Company’s financial instruments consist of trade receivables, trade payables, accrued liabilities, a revolving credit facility and derivative instruments. Trade receivables, trade payables and accrued liabilities are carried at cost and approximate fair value due to the short term nature of these accounts. Our revolving credit facility has a variable interest rate so it also approximates fair value. Derivative instruments are adjusted to fair value every accounting period.

Use of Estimates—The preparation of this balance sheet in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents—The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents.

Accounts Receivable—Trade accounts receivable are recorded at net realizable value which is estimated to be fair value at December 31, 2011 and 2010. If the financial condition of the Company’s customers were to deteriorate, resulting in an impairment of their ability to make payments, additional allowances may be required. Delinquent trade accounts receivable are charged against the allowance for doubtful accounts once collectibility has been determined.

The Company’s crude oil and natural gas receivables are generally collected within two months. The Company accrues an allowance on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any allowance may be reasonably estimated.

Inventory of Oilfield Equipment—Inventory consists of material and supplies used in connection with the Company’s drilling program. These inventories are stated at the lower of average cost or market which as of December 31, 2011 and 2010 approximated fair value.

Oil and Gas Producing Activities—The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells will be capitalized at cost when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs will be charged to expense. The costs of development wells will be capitalized whether productive or nonproductive. Costs incurred to maintain wells and related equipment and lease and well operating costs are charged to expense as incurred. Gains and losses arising from sales of properties will be included in income. However, sales that do not significantly affect a field’s unit-of-production depletion rate will be accounted for as normal retirements with no gain or loss recognized. Geological and geophysical costs of exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred.

Depletion, depreciation and amortization (“DD&A”) of capitalized costs of proved oil and gas properties are provided for on a field-by-field basis using the units of production method based upon proved reserves. The computation of DD&A takes into consideration the anticipated proceeds from equipment salvage and the Company’s expected cost to abandon its well interests.

The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets’ net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property will be written down to “fair value.” Fair value for oil and natural gas properties is generally determined based on discounted future net cash flows.

For the year ended December 31, 2011, the Company recorded $3.5 million of proved property impairments on the Company’s legacy California assets and $0.6 million of proved property impairment in one non-core field in Southern Arkansas. The impairments of the Company’s legacy assets in California were related to steam flooding results that were lower than expected and the impairment of the non-core field in Southern Arkansas was related to the loss of a lease. For the year ended December 31, 2009, our predecessor; BCEC, recorded proved property impairment expense of $0.6 million to write off the remainder of the property balance for the Red Springs field in Wyoming. These calculations involved significant unobservable inputs and, therefore, they are Level 3 fair value estimates.

The Company records the fair value of a liability for an asset retirement obligation as an asset and a liability when there is a legal obligation associated with the retirement of a long-lived asset and the amount can be reasonably estimated. Refer also to Note 10 for additional information on the Company’s asset retirement obligations.

Long-Lived Assets—Long-lived assets to be held and used or disposed of other than by sale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. When required, impairment

losses on assets to be held and used or disposed of other than by sale are recognized based on the fair value of the asset. Long-lived assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less cost to sell.

Other Property and Equipment—Property and equipment acquired at the time of the Company’s corporate restructuring at December 23, 2010 as described in Note 1, were recorded at fair value as of December 23, 2010. Property additions subsequent to December 23, 2010 have been recorded at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, which range from three to ten years.

Revenue Recognition—The Company records revenues from the sales of crude oil and natural gas when delivery to the customer has occurred and title has transferred, net of royalties, discounts and allowances, as applicable. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred. The Company has interests with other producers in certain properties in which case the Company uses the entitlement method to account for gas imbalances. Gas imbalances as of December 31, 2011 and 2010 were immaterial.

For gathering and processing services, the Company either receives fees or commodities from natural gas producers depending on the type of contract. Under the percentage-of-proceeds contract type, the Company is paid for its services by keeping a percentage of the natural gas liquids (“NGL”) produced and a percentage of the residue gas resulting from processing the natural gas. Commodities received are, in turn, sold and recognized as revenue in accordance with the criteria outline above.

Income Taxes—The Company accounts for income taxes under the liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.

Uncertain Tax Positions—The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The tax returns for 2008, 2009, and 2010 are still subject to audit by the internal revenue service.

Concentrations of Credit Risk—The Company has maintained cash balances in excess of the Federal Deposit Insurance Corporation (FDIC) insured limit.

As of December 31, 2011, Lion Oil Trading & Transport and Plains Marketing accounted for 34% and 47%, respectively, of oil and natural gas sales. For the year ended December 31, 2011, Lion Oil Trading & Transport and Plains Marketing accounted for 35% and 45%, respectively, of oil and natural gas sales. For the year ended December 31, 2010 Lion Oil Trading & Transport and Plains Marketing accounted for 52% and 30%, respectively, of oil and natural gas sales.

Risks and Uncertainties—Historically, oil and gas prices have experienced significant fluctuations and have been particularly volatile in recent years. Price fluctuations can result from variations in weather, levels of regional or national production and demand, availability of transportation capacity to other regions of the country and various other factors.

Oil and Gas Derivative Activities—The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities at fair value.

The Company is exposed to commodity price risk related to oil and gas prices. To mitigate this risk, the Company enters into oil and gas forward contracts as economic hedges. The contracts, which are generally placed with major financial institutions or with counter parties which management believes to be of high credit quality, may take the form of futures contracts, swaps or options. The oil and gas reference prices of these contracts are based upon oil and natural gas futures, which have a high degree of historical correlation with actual prices received by the Company.

Prior Year Reclassifications—Certain predecessor balances have been reclassified to conform to the current year presentation, and such reclassifications had no impact on net income or stockholders equity previously reported.

In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). The objective of ASU 2011-11 is to require an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. ASU 2011-11 is effective for interim and annual reporting periods beginning on or after January 1, 2013

and should be applied retrospectively. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

In May 2011, the FASB issued Accounting Standards Update No. 2011-04, Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”), which provides amendments to FASB ASC Topic 820, Fair Value Measurement. The objective of ASU 2011-04 is to create common fair value measurement and disclosure requirements between GAAP and International Financial Reporting Standards (“IFRS”). The amendments clarify existing fair value measurement and disclosure requirements and make changes to particular principles or requirements for measuring or disclosing information about fair value measurements. These amendments are not expected to have a significant impact on companies applying GAAP. ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The adoption of this standard will not have an impact on the Company’s consolidated financial statements other than additional disclosures

In December 2010, the FASB issued Accounting Standards Update No. 2010-29, Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations (ASU 2010-29), which provides amendments to FASB ASC Topic 805, Business Combinations. The objective of ASU 2010-29 is to clarify and expand the pro forma revenue and earnings disclosure requirements for business combinations. ASU 2010-29 was adopted effective January 1, 2011 and did not have an impact on the Company’s consolidated balance sheet other than additional disclosures.

In January 2010, the FASB issued Accounting Standards Update No. 2010-06, Improving Disclosures about Fair Value Measurements (ASU 2010-06), which provides amendments to FASB ASC Topic 820, Fair Value Measurements and Disclosures. The objective of ASU 2010-06 is to provide more robust disclosures about (i) the different classes of assets and liabilities measured at fair value, (ii) the valuation techniques and inputs used, (iii) the activity in Level 3 fair value measurements, and (iv) significant transfers between Levels 1, 2 and 3. ASU 2010-06 was effective for fiscal years and interim periods beginning after December 15, 2009, except for the activity in Level 3 measurement disclosures which was effective January 1, 2011. The Company adopted ASU 2010-06 effective December 31, 2010.

In December 2008, the SEC issued Modernization of Oil and Gas Reporting: Final Rule, which published the final rules and interpretations updating its oil and gas reporting requirements. The final rule includes updated definitions in the existing oil and gas rules to make them consistent with the petroleum resource management system, which is a widely accepted standard for the management of petroleum resources that was developed by several industry organizations. Key revisions included the ability to include nontraditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determine reserves in that companies must use a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months that make up the reporting period. In January 2010, the FASB issued Accounting Standards Update No. 2010-03, Oil and Gas Reserve Estimation and Disclosures (ASU 2010-03), which provides amendments to FASB ASC topic Extractive Activities-Oil and Gas. The objective of ASU 2010-03 is to align the oil and gas reserve estimation and disclosure requirements of the FASB ASC with the requirements in the SEC’s Modernization of Oil and Gas Reporting: Final Rule. BCEC and HEC, the predecessor companies adopted the new rules effective December 31, 2009, and as a result, the Company’s reserves were prepared in accordance with the new reserve definitions in ASU 2010-03 that conform to the SEC’s revised reserve definitions. Oil and gas reserve quantities or their values are a significant component of the Company’s depreciation, depletion and amortization, asset retirement obligation, and proved property impairment analyses. Due to the number of estimates that rely upon reserve quantities and values, any significant changes to the Company’s oil and gas reserves has a pervasive effect on the Company’s consolidated balance sheet, and it is therefore impracticable to estimate the effect that the adoption of ASU 2010-03 had on the Company’s consolidated balance sheet.

3. ACQUISITIONS:

On December 23, 2010, the Company completed the following transactions: (i) the sale of 21,166,134 shares of common stock for $12.52 per share; (ii) the issuance of 6,272,851 shares of common stock valued at $12.52 per share to the holders of BCEC in exchange for all of BCEC’s ownership in Bonanza Creek Energy Operating Company, LLC (a wholly owned subsidiary); and (iii) the acquisition of all of the ownership of HEC for approximately $59 million in cash and 1,683,536 shares of its common stock valued at $12.52 per share. As part of the transactions, the Company also retired debt of approximately $182 million for cash and paid approximately $17 million for debt extinguishment penalties assumed as part of the merger. Because the penalties for the extinguishment of debt were considered as part of the liabilities assumed, the penalties were allocated to the assets acquired and the liabilities assumed as part of the purchase price. Furthermore, a deferred tax liability was recorded based on the difference between the tax basis of the contributed assets and liabilities and their fair value at an effective tax rate of approximately 37%. Fair value was allocated to the assets contributed and liabilities assumed as follows:

Supplemental Pro Forma Results (unaudited)—The following unaudited pro forma financial information represents the combined results for BCEI, BCEC, and HEC for year ended December 31, 2010 as if the contribution and acquisition had occurred on January 1, 2010. The adjustment to depreciation, depletion and amortization assumes that the oil and gas property step up in basis occurred January 1, 2010.

The pro forma financial information is not intended to represent or be indicative of the consolidated results of operations or financial condition of the Company that would have been reported had the acquisition been completed as of the dates presented, and should not be taken as representative of the future consolidated results of operations of the Company.

4. OTHER ASSETS:

The Company has multiple certificates of deposit at three financial institutions to meet financial bonding requirements in the states of Colorado, Wyoming and California. As of December 31, 2011 and 2010 the certificates of deposit totaled $645,000.

As of December 31, 2011 and 2010, the Company had a note receivable of $0 and approximately $987,000, respectively from the operator of the Sargent field. This note receivable was paid in full during February of 2011.

As of December 31, 2011 and 2010, the Company had approximately $2,774,000, and $1,494,000, respectively of unamortized deferred financing costs related to the bank revolving credit agreement that was retained by the Company.

5. ACCOUNTS PAYABLE AND ACCRUED EXPENSES:

Accounts payable and accrued expenses contain the following:

6. LONG-TERM DEBT:

Senior Secured Revolving Credit Facility—On March 29, 2011, the Company entered into a Senior Secured Revolving Credit Agreement, (the “Revolver”), with a syndication of banks, with BNP Paribas as the administrative agent and issuing lender, which provides for borrowings of up to $300 million. The Revolver provides for interest rates plus an applicable margin to be determined based on LIBOR or a bank base rate (the “Base Rate”), at the Company’s election. LIBOR borrowings bear interest at LIBOR plus 1.75% to 2.75% depending on the utilization level and the Base Rate borrowings bear interest at the “Bank Prime Rate,” as defined plus .75% to 1.75%.

The Revolver has a $220 million borrowing base as of December 31, 2011 and is subject to semi-annual re-determinations in April and October of each year. The Revolver provides for commitment fees of .375% to 0.50%, depending on utilization, and restricts, among other items, the payment of dividends, certain additional indebtedness, sale of assets, loans, certain investments and mergers. The Revolver also contains certain financial covenants, which require the maintenance of a minimum current ratio and a minimum debt coverage ratio, as defined. The Company was in compliance with these covenants as of December 31, 2011. The Revolver is collateralized by substantially all the Company’s assets and matures on September 15, 2016.

7. COMMITMENTS AND CONTINGENT LIABILITIES:

Office Leases—The Company rents office facilities under various noncancelable operating lease agreements. The Company’s noncancelable operating lease agreements result in total future minimum noncancelable lease payments are presented below. The Company also has principal payment requirements for its line of credit which is also presented below:

Environmental—The Company is engaged in oil and gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures as they relate to the drilling of oil and gas wells and the operations. Relative to the Company’s acquisition of existing or previously drilled well bores, the Company may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean up or restoration, the liability to cure such a violation could fall upon the Company. Management believes its properties are operated in conformity with local, state and federal regulations. No claims have been made, nor is the Company aware of any uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration or the violation of any rules or regulations.

Legal Proceedings—The Company may from time to time be involved in various other legal actions arising in the normal course of business. During the second quarter of 2011, our Board of Directors formed a Special Litigation Committee comprised of three non-executive directors to investigate the merits of a demand for arbitration against our current President and Chief Executive Officer from the former Chairman of BCEC related to the management of BCOC and BCEC during 2005 and 2006. These demands do not allege any wrongdoing by or claims against the Company. The Special Litigation Committee retained outside independent advisors to conduct the investigation and concluded that the allegations were without merit. The Company’s general and administrative expense includes approximately $1.0 million related to this matter for the year ended December 31, 2011.

8. STOCKHOLDERS’ EQUITY:

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

On December 23, 2010 the Company issued 21,166,134 shares of common stock to West Face Capital and to certain clients of AIMCo at $12.52 per share. Also as part of the formation on December 23, 2010 BCEC contributed all of its ownership interest in Bonanza Creek Energy Operating Company, LLC to the Company for 6,272,851 shares of its common stock valued at $12.52 per share. In addition, on December 23, 2010, the Company issued 1,683,536 shares of its common stock valued at $12.52 per share to the majority owner of HEC and a member of Bonanza Creek Energy, Inc.’s management who also owned a minority interest of HEC (refer to Note 3).

Management Incentive Plan—On December 23, 2010, the Company established the Management Incentive Plan (the “Plan” or “MIP”) for the benefit of certain employees, officers and other individuals performing services for the Company. The maximum number of shares of Class B common stock available under the Plan is 10,000 and these shares were converted into 437,787 shares of restricted common stock upon completion of our initial public offering. The conversion rate was determined based on a formula factoring in the rate of return to the common stockholders. The 437,787 shares of common stock that were granted to employees were valued at $17.00 per share on the grant date and vest over a three year period. Non-cash compensation expense of $122,000 was recorded during the year ended December 31, 2011 and there was $7,320,000 of unrecognized compensation costs related to the unvested restricted common stock granted under the plan. That cost is expected to be recognized over a period of 2.9 years.

BCEC Management Incentive Plan—In connection with the corporate restructuring described in Note 1, 317,142 shares of common stock of BCEI were designated for holders of BCEC’s Class B units. These shares were held in trust for the benefit of employees. On December 15, 2011, 243,945 of these shares were valued at $17.00 per share and granted to employees without vesting requirements and the Company recorded a non-cash compensation charge in the amount of $4,147,000. As of December 31, 2011, 73,197 shares of BCEI common stock remain held in trust and designated for holders of BCEC’s Class B units. When and if such shares are issued, they will be valued based on the market price of the Company’s common stock on the grant date.

9. INCOME TAXES:

Deferred tax assets and liabilities are measured by applying the provisions of enacted tax laws to determine the amount of taxes payable or refundable currently or in future years related to cumulative temporary differences between the tax bases of assets and liabilities and amounts reported in the Company’s balance sheet. The tax effect of the net change in the cumulative temporary differences during each period in the deferred tax assets and liabilities determines the periodic provision for deferred taxes. The provision for income taxes consists of the following:

Temporary differences between the financial statement carrying amounts and tax bases of assets and liabilities that give rise to the net deferred tax liability result from the following components:

At December 31, 2011, the Company had net operating loss carryforwards for federal tax purposes of approximately $27,465,761. The net operating loss carryforwards will expire in 2031. Reconciliation of the Company’s effective tax rate to the expected federal tax rate of 34% is as follows:

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 $2.1 million with an additional $9.1 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 $11.2 million.

10. ASSET RETIREMENT OBLIGATIONS:

In connection with the Company’s acquisition of BCEC and HEC, asset retirement obligations in the amount of $4,970,441, and $641,268, respectively, were assumed.

The fair value of asset retirement obligation is recorded as a liability when incurred, which is typically at the time the assets are acquired or placed in service. Amounts recorded for the related assets are increased by a corresponding amount of these obligations. Prospectively, the liabilities are accreted for the change in their present value and the initial capitalized costs are depleted, depreciated and amortized over the productive lives of the related assets.