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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

For the transition period from           to           

Commission file number:  001-32471

BLACK RAVEN ENERGY, INC.

 (Exact Name of Registrant as Specified in its Charter)

Registrant’s Telephone Number, including area code:  (303) 308-1330

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o No x

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.  Yes o No x

The number of shares of the registrant’s common stock outstanding as of September 30, 2011 was 17,010,531.

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

Black Raven Energy, Inc.

Condensed Consolidated Balance Sheets

(Unaudited)

(In thousands)

The accompanying notes are an integral part of these condensed consolidated financial statements.

Black Raven Energy, Inc.

Condensed Consolidated Balance Sheets (Continued)

(Unaudited)

(In thousands, except share and per share amounts)

The accompanying notes are an integral part of these condensed consolidated financial statements.

Black Raven Energy, Inc.

Condensed Consolidated Statements of Operations

(Unaudited)

(In thousands, except share and per share amounts)

The accompanying notes are an integral part of these condensed consolidated financial statements.

Black Raven Energy, Inc.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(In thousands)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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BLACK RAVEN ENERGY, INC.

Notes to Condensed Consolidated Financial Statements

September 30, 2011

(Unaudited)

Note 1—Description of Business, Basis of Presentation and Summary of Significant Accounting Policies

Description of Business

Black Raven Energy, Inc.  and its subsidiaries (“Black Raven,” the “Company,” “us,” “our” or “we”), operate as an independent energy company engaged in the acquisition, exploitation, development and production of natural gas and oil in the Rocky Mountain region of the United States.

On March 5, 2008, the Company (under its former name, PRB Energy, Inc.) and its subsidiaries filed voluntary petitions for relief (the “Chapter 11 Bankruptcy”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Colorado (the “Bankruptcy Court”).  The Company continued to operate its business as a “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.  On January 16, 2009, the Bankruptcy Court entered an order confirming a Modified Second Amended Joint Plan of Reorganization (the “Plan”) of  the Company and PRB Oil and Gas, Inc. (“PRB Oil”), which was then a wholly-owned subsidiary.  The effective date of the Plan was February 2, 2009 (the “Effective Date”).  After the Effective Date, PRB Oil was merged into the Company.    On the Effective Date, we issued an Amended and Restated Senior Secured Debenture (the “Amended Debenture”) payable to West Coast Opportunity Fund, LLC (“WCOF”), the principal pre-petition secured creditor, in the original principal amount of $18,450,000.  WCOF also became our principal stockholder as of the Effective Date.

Effective November 1, 2008, control of the Recluse Gathering System owned by PRB Gathering, Inc. (“PRB Gathering”), a wholly-owned subsidiary, was turned over to a receiver appointed by the State Court of Wyoming. Based on our loss of control, we deconsolidated PRB Gathering during the fourth quarter of 2008.  PRB Gathering was dismissed from Chapter 11 Bankruptcy on February 17, 2010, and a gain on reorganization of approximately $1.1 million was recognized.  Upon PRB Gathering’s dismissal from bankruptcy, the Company reacquired control of PRB Gathering.  PRB Gathering has no significant assets or liabilities as of September 30, 2011 and December 31, 2010 and no significant operations for the nine months ended September 30, 2011 and 2010.

The accompanying condensed consolidated financial statements have been prepared assuming the Company will continue as a going concern.  As shown in the accompanying financial statements, the Company continues to experience net losses from its operations, reporting a net loss of $1.49 million for the nine months ended September 30, 2011.   Cash and cash equivalents on hand and internally generated cash flows may not be sufficient to execute the Company’s business plan.  Future bank financings, asset sales, or other equity or debt financings may be required to fund the Company’s debt service, working capital requirements, planned drilling, potential acquisitions and other capital expenditures.  These conditions raise substantial doubt about the Company’s ability to continue as a going concern.   These financial statements do not include any adjustments that may result from the outcome of this uncertainty.

The Company entered into a Farmout Agreement dated July 23, 2010 (the “Farmout Agreement”) with Atlas Resources, LLC (“Atlas”), as further discussed in Note 3.  The Farmout Agreement is expected to provide the Company sufficient cash flow to continue drilling operations on behalf of Atlas on the properties subject to the agreement. There can be no assurances that the cash flow generated from the Farmout Agreement will be sufficient to execute the Company’s business plan.

On July 27, 2011, the Company completed the purchase of the oil and gas properties in the Adena Field in Morgan County, Colorado (the “Adena Properties”) as further discussed in Note 4.  In order to finance this purchase, the Company entered into a note purchase agreement with Carlyle Energy Mezzanine Opportunities Fund and its affiliates (collectively “Carlyle”), as further discussed in Note 6.

Basis of Presentation

The accompanying unaudited interim condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) and generally accepted accounting principles in the United States (“GAAP”). In the opinion of management, the condensed consolidated financial statements include the adjustments, consisting of normal recurring accruals, necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been

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condensed or omitted from these statements pursuant to such rules and regulations.  Accordingly, these financial statements should be read in conjunction with our audited consolidated financial statements, included in our Annual Report on Form 10-K for the year ended December 31, 2010.  The results for interim periods are not necessarily indicative of the results for the entire year.

In connection with the preparation of the condensed consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of September 30, 2011, through the filing date of this report.

Summary of Significant Accounting Policies

The accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in its Annual Report on Form 10-K for the year ended December 31, 2010 (“2010 10-K”), and are supplemented throughout the notes to the condensed consolidated financial statements in this report.  These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in the 2010 Form 10-K.

Net Earnings (Loss) Per Share - We account for earnings (loss) per share (“EPS”) in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 260, “Earnings per Share” (“ASC Topic 260”).  Under ASC Topic 260, basic EPS is computed by dividing the net loss applicable to common stockholders by the weighted average common shares outstanding without including any potentially dilutive securities.   Potentially dilutive securities for the diluted earnings per share calculation consist of in-the-money outstanding warrants and stock options to purchase our common stock for the periods ended September 30, 2011 and 2010. Diluted EPS is computed by dividing the net loss applicable to common stockholders for the period by the weighted average common shares outstanding plus, when their effect is dilutive, common stock equivalents.  For the nine months ended September 30, 2011 and 2010, and the three months ended September 30, 2011 and 2010, there were no potentially dilutive securities outstanding whose effect would be dilutive to our earnings (loss) per share calculation.

Potentially dilutive securities, which have been excluded from the determination of diluted earnings (loss) per share because their effect would be anti-dilutive, are as follows:

Subsequent to September 30, 2011, and through the filing date of this report, we have not issued any dilutive securities that would have increased the number of potentially dilutive shares.

Concentration of Credit Risk - Revenues from customers that represented 10% or more of our oil and gas sales for the three and nine months ended September 30, 2011 and 2010 were as follows:

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Note 2—Recent Accounting Pronouncements

In January 2010, the FASB issued ASC Update 2010-06, “Fair Value Measurements and Disclosures” (“ASC Update 2010-06”), which requires additional disclosures about the different classes of assets and liabilities measured at fair value, the valuation techniques and inputs used, the fair value measurements of the activity in Level 3 on a gross basis and transfers between Levels 1 and 2. This new authoritative guidance was effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures regarding gross activity in the Level 3 rollforward, which were effective for the Company on January 1, 2011. The adoption of ASC Update 2010-06 did not have a material impact on the Company’s financial statements.

In December 2010, the FASB issued ASC Update 2010-29, “Business Combinations: Disclosure of Supplementary Pro Forma Information for Business Combinations”, which amended FASB ASC Topic 805, “Business Combinations”. The objective of this update is to clarify and expand the pro forma revenue and earnings disclosure requirements for business combinations. The guidance was effective for fiscal years beginning after December 15, 2010, and the Company adopted the provision on January 1, 2011. Adoption of the disclosure requirements did not have a material impact on the Company’s financial position or results of operations.

In May 2011, the FASB issued new fair value measurement authoritative guidance that clarifies the application of fair value measurement and disclosure requirements and changes particular principles or requirements for measuring fair value.  This guidance is effective for annual periods beginning after December 15, 2011.  The Company is currently evaluating this guidance and assessing the impact, if any, it may have on the Company’s fair value disclosures.

In June 2011, the FASB issued new authoritative guidance that states an entity that reports items of other comprehensive income has the option to present the components of net income and comprehensive income in either one continuous financial statement or two consecutive financial statements. This guidance is effective for annual periods beginning after December 15, 2011.  The Company is currently evaluating this guidance and assessing the impact it may have on the Company’s comprehensive income disclosures.

Note 3—Farmout Agreement

On July 23, 2010, the Company entered into a Farmout Agreement with Atlas, a wholly-owned subsidiary of Atlas Energy, Inc., relating to natural gas drilling within an area of mutual interest in Phillips and Sedgwick counties, Colorado and Perkins, Chase and Dundy counties, Nebraska (the “AMI”).

Under the terms of the Farmout Agreement, Atlas agreed to drill six initial wells identified in the Farmout Agreement (the “Initial Wells”) and to complete certain initial projects, including 3D seismic shoots, upgrades of sales meter equipment, and the change-out of compressors and upgrade of a dehydrator at the Company’s facility.  The Company assigned to Atlas all of its title and interest in the defined areas around the planned wellbores (the “Drilling Units”) for the Initial Wells.

The Farmout Agreement also provides for Atlas, at its discretion, to drill additional wells in the AMI in accordance with work plans (each a “Work Plan”) approved by Atlas under the Farmout Agreement.  The initial Work Plan approved by Atlas covering the period from July 23, 2010 to April 30, 2011 provided for Atlas drilling 60 wells.  For each six month period after April 30, 2011, Atlas must submit a proposal to the Company setting forth the numbers of wells that it proposes to drill for such six month period (the “Drilling Proposal”) and the Company must provide a Work Plan to be approved by Atlas outlining the development plan for the wells set forth in the Drilling Proposal.  In the event that Atlas determines not to drill at least 60 wells in the course of any six month period, the Company has the right, during such six month period, to drill for its own account that number of wells equal to the difference between 60 wells and the number of wells agreed to be drilled by Atlas.  Upon payment of a well-site fee, delivery of an executed authorization for expenditure (“AFE”) for such well by Atlas, and completion of drilling the applicable well, the Company will assign all of its rights, title and interest in the Drilling Units established for such well.  The Farmout Agreement also provides for certain rights of the Company and Atlas with respect to the drilling of “deep wells” and for the payment by Atlas of drilling and future 3D seismic costs.

As of September 30, 2010, drilling of the Initial Wells had been completed, and through the first quarter of 2011, Atlas had funded and drilled an additional 40 wells pursuant to the initial Work Plan. On June 3, 2011, Atlas submitted its Drilling Proposal for the six month period beginning May 1, 2011 in which it proposed to drill 135 wells after July 1, 2011.  The Company

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submitted a Work Plan which Atlas approved and drilling commenced on August 15, 2011.  As of September 30, 2011, an additional 37 wells had been funded and drilled pursuant to the Work Plan, for a total of 83 wells.

Restricted cash of $19.6 million and $5.6 million at September 30, 2011 and December 31, 2010, respectively, includes cash received from Atlas for drilling activities in connection with oil and gas properties subject to the Farmout Agreement.  The accounts payable balances at September 30, 2011 and December 31, 2010 contain drilling costs related to the Farmout Agreement of $2.4 million and $0.8 million, respectively.   Advances from Atlas of $20.1 million at September 30, 2011 include cash received from Atlas for drilling activities in connection with oil and gas properties subject to the Farmout Agreement.  Advances from Atlas of $4.8 million at December 31, 2010 include cash received from Atlas for drilling activities in connection with oil and gas properties subject to the Farmout Agreement.

In consideration for the agreements made under the Farmout Agreement, Atlas paid the Company $1,000,000 upon execution of the Farmout Agreement.  In addition, Atlas agreed to pay the Company a $60,000 well-site fee for each well drilled by Atlas in the AMI, including the Initial Wells.  As of September 30, 2011, the Company had received $4,980,000 of well site fees for the 83 wells drilled through September 30, 2011.  The Company also received prepaid well site fees of $2.9 million for wells to be drilled in the fourth quarter of 2011.

The Company will also receive an undivided six percent of eight eighths (6% of 8/8ths) overriding royalty interest on substantially all of the oil and gas produced and sold that is attributable to the Drilling Units assigned to Atlas under the Farmout Agreement, subject to certain deductions.  The average overriding royalty interest on the first 83 wells drilled is 5.70%.

The term of the Farmout Agreement is ten years, subject to earlier termination pursuant to the terms set forth therein.

On August 11, 2010, in connection with the Farmout Agreement and ongoing investment advisory services, the Company entered into an advisory fee agreement with a third party, whereby the Company agreed to pay $10,000 per well for the first 220 wells that are funded and drilled by Atlas under the Farmout Agreement discussed above, up to a maximum fee of $2.2 million.  As of September 30, 2011, Atlas had funded and drilled 83 wells, and the Company had paid advisory fees of $830,000.

Note 4 —Acquisitions

Marks Butte Acquisition

On June 6, 2011, the Company acquired from Diamond Operating all of its interests in the Marks Butte area of Sedgwick County, Colorado.  The purchase price was $98,500 in cash, and included title and interest in all oil and gas leases, all easements, rights-of —way, a 100% working interest in two shut-in wells, 6.15 miles of pipeline and compressor station with a tap into the Trailblazer Pipeline.  The Company acquired the assets in order to utilize the tap for the planned drilling in the East Marks Butte area as part of the Farmout Agreement.

The preliminary purchase price allocation, which is subject to final purchase price allocation adjustments, is as follows (in thousands):

Adena Field Acquisition

On July 27, 2011, the Company completed the purchase of the Adena Properties.  The acquisition consists of an 80% working interest in 18,760 gross acres, with a net purchase price of $15.24 million, subject to adjustments for production after the effective date and other matters.  The effective date of the Adena Property acquisition was May 1, 2011.  The Company will operate the Adena Properties.  The Company has entered into an agreement with a strategic partner which will provide geological, engineering, and management services associated with this project and will earn 24% of the Company’s 80% working interest after payout of all costs, including financing costs.  The Adena Properties consist of an existing waterflood in the J Sand, and a conventional oil field in the D Sand.  In addition, there is a gas cap in the J Sand that can be produced in the future.  The acquisition was financed by Carlyle (see Note 6).

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The preliminary purchase price allocation, which is subject to final purchase price allocation adjustments, is as follows (in thousands):

The Adena Properties acquisition qualified as a business combination and, as such, the Company estimated the fair value of the assets acquired as of the acquisition date, July 27, 2011. To estimate the fair values of the properties as of the acquisition date, the Company used a net asset value approach. The Company utilized a discounted cash flow model that took into account the following inputs to arrive at estimates of future net cash flows:

·                  Estimated ultimate recovery of crude oil and natural gas as prepared by the Company’s petroleum engineers;

·                  Estimated future commodity prices based on NYMEX crude oil futures prices as of the acquisition date and adjusted for estimated location and quality differentials as well as related transportation costs;

·                  Estimated future production rates; and

·                  Estimated timing and amounts of future operating and development costs.

To estimate the fair value of proved properties, the Company discounted the future net cash flows using a market-based rate that the Company determined appropriate at the acquisition date for the various proved reserve categories. To compensate for the inherent risk of estimating and valuing unproved properties, the Company reduced the discounted future net cash flows of the unproved properties by additional risk-weighting factors.

The results of operations from the Adena Property Acquisition are included in the Company’s condensed consolidated financial statements from the acquisition date of July 27, 2011.  The pro forma results of operations, presented as if the Company had acquired the Adena Properties on January 1, 2010, for the nine months ended September 30, 2011 and 2010 are as follows:

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Note 5 —Asset Retirement Obligations

The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties.  A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired.  The increase in carrying value is included in proved oil and gas properties in the accompanying condensed consolidated balance sheets.  The Company depletes the amount added to proved oil and gas property costs and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and gas properties.  Cash paid to settle asset retirement obligations is included in the operating section of the Company’s accompanying condensed consolidated statements of cash flows.

The Company’s estimated asset retirement obligation liability is based on historical experience in abandoning wells, estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements.  The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised.  Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells.

A reconciliation of the Company’s asset retirement obligations is as follows:

Note 6—Borrowings

As of September 30, 2011 and December 31, 2010, our borrowings consisted of the following:

Amended Senior Secured Debenture

On the Effective Date, in connection with the consummation of the Plan, we, along with PRB Oil, entered into a Limited Waiver, Consent and Modification Agreement (the “Modification Agreement”) with WCOF.  Under the Modification Agreement, we issued the Amended Debenture, payable to WCOF in the original principal amount of $18.45 million.

Since its issuance, the terms of the Amended Debenture have been modified on several occasions.  Currently, a total of approximately $18.85 million of principal is outstanding under the Amended Debenture.   The outstanding principal bears interest at a total of ten percent (10%) per annum and is due and payable on January 15, 2014.   Interest is paid to WCOF on the outstanding principal at a rate equal to five percent (5%) per annum in shares of common stock of the Company in an amount based on a share price of $2.00 per share (the “Stock Interest”).  Additional interest is payable to WCOF on the outstanding

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principal at a rate equal to five percent (5%) per annum in cash (the “Cash Interest”).  The Stock Interest is due and payable to WCOF quarterly in arrears on the last day of each calendar quarter. The Cash Interest is due and payable to WCOF on the maturity date of the Amended Debenture, less $5,000 per well drilled under the Farmout Agreement (see Note 3), which is payable to WCOF upon the Company’s receipt of the applicable well-site fees from Atlas under the Farmout Agreement.

We have guaranteed payment of the Amended Debenture and pledged substantially all of our assets as collateral.  If we fail to comply with the restrictions in the agreements governing the Amended Debenture, an event of default could occur that would permit WCOF to foreclose on substantially all of our assets.  The Company and WCOF have agreed that no event of default shall occur on the Amended Debenture until written notice of default is given to the Company by WCOF and such default shall have continued for a period of 30 days after written notice is delivered to the Company.

In connection with the financing of the Adena Properties acquisition described below, WCOF agreed to subordinate the payment obligations under the Amended Debenture and related security interests to the payment obligations arising under the Adena acquisition financing, pursuant to the terms and conditions of an intercreditor and subordination agreement.  As further security for the payment of the notes, WCOF, which is also the majority stockholder in the Company, pledged to the lenders all of its shares of stock in the Company.

Senior Secured Notes

On July 27, 2011, in order to finance the acquisition of the Adena Properties, the Company entered into a note purchase agreement (the “Note Purchase Agreement”) with Carlyle as administrative agent and collateral agent.  Pursuant to the Note Purchase Agreement, the Company closed on the issuance and sale of Tranche A promissory notes (the “Tranche A Notes”) in the aggregate principal amount of $18.0 million. The Tranche A Notes mature and are due and payable on July 27, 2016. They bear interest at a stated rate of 13% per annum, of which 10% must be paid in cash, and, at the election of the Company, 3% may be paid in cash or paid in kind and capitalized into the Tranche A Notes. A portion of the proceeds received from the sale of the Tranche A Notes was used for the acquisition of the Adena Properties with the balance to be used according to a mutually approved plan of development for the Adena Properties. The Company was required to establish a reserve account pursuant to the Note Purchase Agreement in the amount of $450,000, which is included in restricted cash (non-current) within the condensed consolidated balance sheets.

Subject to certain conditions, the Company can voluntarily prepay the Tranche A Notes.  If the Company prepays the Tranche A Notes before July 31, 2014, subject to certain exceptions, the Company must pay a “make-whole” amount, equal to the present value at the time of the prepayment of the amount of interest which would have been payable on the principal balance of the Tranche A Notes through July 31, 2014.

Concurrently with the issuance of the Tranche A Notes, the Company issued to the holders of the Tranche A Notes Tranche B promissory notes (“Tranche B Notes, and with the Tranche A Notes the “Senior Secured Notes”) in the aggregate principal amount of $2.5 million with a stated interest rate of 13% per annum, all of which is paid in kind and capitalized into the Tranche B Notes. The Company may prepay the Tranche B Notes only in whole, and upon prepayment, the Company must pay a “make-whole” amount, equal to $1.2 million less the amount of paid in kind interest that has been capitalized into the Tranche B Notes as of such date.  The Tranche B Notes have been recorded net of a discount of $2.5 million, which is being amortized over the life of the loan.  For the three and nine months ended September 30, 2011, amortization of debt discount was $83,000.  The Tranche B Notes are due and payable on the earlier of July 27, 2016, or the repayment of the Tranche A Notes.

The Company incurred deferred financing costs totaling $1.8 million in connection with the issuance of the Senior Secured Notes.  As additional consideration for the issuance of the Senior Secured Notes, the Company conveyed to the holders of the Senior Secured Notes overriding royalty interests equal to 3% of 8/8ths in the Adena Properties and agreed to convey overriding royalty interests in any future oil and gas properties acquired by the Company, subject to certain permissible acquisitions, during the term of the Note Purchase Agreement.  The Company has estimated the value of the overriding royalty interests to be $2.2 million at the date of the financing and has recorded additional deferred financing costs associated with its Senior Secured Notes related to these interests.  The Company’s deferred financing costs will be amortized to interest expense over the term of the Note Purchase Agreement.  If future overriding royalty interests in oil and gas properties acquired by the Company are conveyed to Carlyle under the terms of the Note Purchase Agreement, additional deferred financing costs will be recorded and amortized as an adjustment to the yield on the Senior Secured Notes over the remaining period of the Note Purchase Agreement.  Depending on the nature of any future acquisitions made by the Company, the value of the applicable overriding royalty interests conveyed to Carlyle may be material to the Company’s financial position or results of operations.

The Senior Secured Notes are collateralized by substantially all of the assets of the Company and its subsidiaries. The Senior Secured Notes are subject to customary events of default.  Upon the occurrence of an event of default, as described in the Note Purchase Agreement, the payment of the principal amounts under the Senior Secured Notes may be accelerated and the

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interest rate applicable to the principal amounts will be increased to a stated interest rate of 16% per annum during the period the default exists. WCOF, a majority stockholder in the Company and the holder of the Amended Secured Debentures discussed above, agreed to subordinate the payment obligations under the debenture and related security interests to the payment obligations arising under the Senior Secured Notes and the security interests securing payment of the Senior Secured Notes, pursuant to the terms and conditions of an intercreditor and subordination agreement.  As further security for the payment of the Senior Secured Notes, WCOF pledged to Carlyle all of its shares of stock in the Company.

As of September 30, 2011, $96,000 of interest had been converted to debt.

Note 7—Income Taxes

Income tax expense during interim periods is based on applying an estimated annual effective income tax rate to year-to-date income, plus any significant, unusual or infrequently occurring items which are recorded in the interim period.  The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, the expected operating income or loss for the year, projections of the proportion of income earned and taxed in various jurisdictions, permanent and temporary timing differences, and the likelihood of recovering deferred tax assets generated in the current and prior years.  The accounting estimates used to compute the provision for income taxes may change as new events occur, more experience is acquired, additional information is obtained or as the tax environment changes.

The provision for income taxes for the nine months ended September 30, 2011 and 2010 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 35% to pre-tax income because of state income taxes, non-deductible interest expense and the Company’s valuation allowance.

In assessing the need for a valuation allowance on the Company’s deferred tax assets, all available evidence, both negative and positive, was considered in determining whether it is more likely than not that some portion or all of the deferred tax assets will be realized.  Based on this assessment, the Company has recorded a full valuation allowance against its net deferred tax asset as of September 30, 2011.  The Company’s evaluation of the amount of the deferred tax asset considered more likely than not to be realizable will likely change in future periods as estimates of future income change due to changes in expected future oil and gas prices and other factors, and these changes could be material.

The Company accounts for its uncertain tax positions in accordance with the provisions of the ACS Topic 740, “Income Taxes”.  During the nine months ended September 30, 2011, there was no change to the Company’s liability for uncertain tax positions.

Note 8—Equity Compensation Plan

In June 2009, the Board of Directors of the Company adopted the Black Raven Energy, Inc. Equity Compensation Plan (the “Equity Compensation Plan”) under which we may grant nonqualified stock options, stock appreciation rights, stock awards or other equity-based awards to certain of our employees, consultants, advisors and non-employee directors.  The Board initially reserved 3,791,666 shares of common stock for issuance under the Equity Compensation Plan and that number is adjusted annually to 25% of shares issued and outstanding on July 1.  As of September 30, 2011, there were 4,223,264 shares of common stock authorized for issuance under the Equity Compensation Plan.

The following table summarizes activity for options:

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The Company recorded equity compensation expense, which is included in general and administrative expenses in the condensed consolidating statements of operations, of $235,000 during the nine months ended September 30, 2011 and $242,000 during the nine months ended September 30, 2010.

Note 9 —Commitments and Contingencies

In the normal course of business operations, the Company has entered into operating leases for office space and office equipment. Rental payments under these operating leases totaled $91,000 and $82,000 for the nine months ended September 30, 2011 and 2010, respectively, and are included in general and administrative expenses in the condensed consolidating statements of operations.

Note 10 —Derivative Financial Instruments

To mitigate a portion of the exposure to potentially adverse market changes in oil prices and the associated impact on cash flows, the Company has entered into an oil swap contract.  As of September 30, 2011, the Company has a forward contract in place through July 31, 2014 for a total of 72,000 barrels of crude oil production.

The Company’s oil derivatives are measured at fair value and are included in the accompanying condensed consolidated balance sheets as derivative assets.  The fair value is an estimated exit-price that management believes provides a reasonable and consistent methodology for valuing derivative instruments.  The derivative instruments utilized by the Company are not considered by management to be complex, structured, or illiquid.  The oil derivative markets are highly active.  The fair value of the Company’s oil commodity derivative contract was a net asset of $1.1 million at September 30, 2011.

Derivative Assets

(in thousands)

The following table summarizes the realized gain and loss from derivative cash settlements and the unrealized gain and loss from changes in fair value of derivative contracts as presented in the accompanying statements of operations.

For the three and nine months ended September 30, 2010, the Company did not have any derivative financial instruments in place.

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Note 11 —Fair Value Measurements

The Company follows FASB ASC Topic 820, “Fair Value Measurement and Disclosure”, which establishes a three-level valuation hierarchy for disclosure of fair value measurements.  The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.  The three levels are defined as follows:

·                  Level 1:  Quoted Prices in Active Markets for Identical Assets — inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

·                  Level 2:  Significant Other Observable Inputs — inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

·                  Level 3:  Significant Unobservable Inputs — inputs to the valuation methodology are unobservable and significant to the fair value measurement.

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.  The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability.  The Company reflects transfers between the three levels at the beginning of the reporting period in which the availability of observable inputs no longer justifies classification in the original level.

The following tables set forth by level within the fair value hierarchy the Company’s financial assets and financial liabilities as of September 30, 2011 that are measured at fair value on a recurring basis.

As of September 30, 2011

As of December 31, 2010, there were no financial assets or financial liabilities that were measured at fair value on a recurring basis.

The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the tables above:

Derivatives - Commodity derivative instruments consist entirely of crude oil swaps.  The Company’s derivatives are valued using industry-standard models, which are based on a market approach.  These models consider various assumptions, including quoted forward prices for commodities, time value and volatility factors.  These assumptions are observable in the marketplace throughout the full term of the contracts, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are therefore designated as Level 2 within the valuation hierarchy.  The discount rates used in the fair values of these instruments include a measure of either the Company’s or the counterparty’s nonperformance risk, as appropriate.  The Company utilizes counterparties’ valuations to assess the reasonableness of its own valuations.

The following tables set forth by level within the fair value hierarchy the Company’s financial assets and financial liabilities as of September 30, 2011 that were measured at fair value on a non-recurring basis:

As of September 30, 2011

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As of December 31, 2010, there were no financial assets and financial liabilities that were measured at fair value on a non-recurring basis.

The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the tables above:

Properties and Equipment - The Company estimated the fair values of the property and equipment related to the Marks Butte acquisition and the Adena Field acquisition as of the acquisition date, using a net asset value approach. The Company utilized a discounted cash flow model that took into account the following inputs to arrive at estimates of future net cash flows:

To estimate the fair value of proved properties, the Company discounted the future net cash flows using a market-based rate that the Company determined appropriate at the acquisition date for the various proved reserve categories. To compensate for the inherent risk of estimating and valuing unproved properties, the Company reduced the discounted future net cash flows of the unproved properties by additional risk-weighting factors. Due to the unobservable nature of the inputs, the fair values of the proved and unproved oil and gas properties are considered Level 3 fair value measurements.

Other Fair Value Disclosures

Our financial instruments, including cash and cash equivalents, restricted cash, accounts receivable, accounts payable and secured debentures, are carried at cost.  At September 30, 2011, the fair value of the cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates their carrying value due to the short term nature of these instruments.  Due to the nature of the Amended Debenture, the Company is unable to reliably estimate its fair value at September 30, 2011.   The fair value of the Company’s Senior Secured Notes approximates book value due to the recent issuance of these instruments.

ITEM 2.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Forward-Looking Statements

The following discussion contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Quarterly Report that address activities, events, or developments with respect to our financial condition, results of operations, or economic performance that we expect, believe, or anticipate will or may occur in the future, or that address plans and objectives of management for future operations, are forward-looking statements.  The words “anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,” “forecast,” “intend,” “plan,” “project,” “will,” and similar expressions are intended to identify forward-looking statements.

Our forward-looking statements are based on assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions, expected future developments, and other factors that we believe are appropriate under the circumstances.  These statements are subject to a number of known and unknown risks and uncertainties which may cause our actual results and performance to be materially different from any future results or performance expressed or implied by the forward-looking statements.  These risks are described in the “Risk Factors” section of our 2010 Form 10-K.

Overview

You should read the following discussion in conjunction with the unaudited condensed consolidated financial statements and related notes in Item 1 and the audited consolidated financial statements and related notes in our 2010 Form 10-K.

The accompanying condensed consolidated financial statements have been prepared assuming the Company will continue as a going concern.  As shown in the accompanying condensed consolidated financial statements, the Company continues to experience net losses from its operations, reporting a net loss of $1.49 million for the nine months ended September 30, 2011.   Cash and cash equivalents on hand and internally generated cash flows may not be sufficient to execute the Company’s business

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plan.  Future bank financings, asset sales, or other equity or debt financings may be required to fund the Company’s debt service, working capital requirements, planned drilling, potential acquisitions and other capital expenditures.  These conditions raise substantial doubt about the Company’s ability to continue as a going concern.   The financial statements do not include any adjustments that may result from the outcome of this uncertainty.

The Company entered into a Farmout Agreement dated July 23, 2010 with Atlas, as further discussed in Notes 1 and 3 to the condensed consolidated financial statements.  The Farmout Agreement is expected to provide the Company sufficient cash flow to continue drilling operations on behalf of Atlas on the properties subject to the agreement.  There can be no assurances that the cash flow generated from the Farmout Agreement will be sufficient to execute the Company’s business plan.

As of September 30, 2010, drilling of the six Initial Wells had been completed, and through the first quarter of 2011, Atlas had funded and drilled an additional 40 wells pursuant to the initial Work Plan.  On June 3, 2011, Atlas submitted its Drilling Proposal for the six month period beginning May 1, 2011 in which it proposed to drill 135 wells after July 1, 2011.  Drilling began on August 15, 2011, and as of September 30, 2011 an additional 37 wells had been funded and drilled, for a total of 83 wells.

In consideration for the agreements made under the Farmout Agreement, Atlas paid the Company $1,000,000 upon execution of the Farmout Agreement.  In addition, Atlas agreed to pay the Company a $60,000 well-site fee for each well drilled by Atlas, including the Initial Wells.  As of September 30, 2011, the Company had received $4,980,000 of well site fees for 83 wells drilled through September 30, 2011, and the Company had paid fees of $830,000 to a third party advisor pursuant to an advisory fee agreement.  If the additional 98 wells are drilled under the current Work Plan, the Company will receive $5,880,000 in well site fees and would be obligated to pay the third party advisor $980,000 pursuant to the advisory fee agreement.  See Note 3 to the condensed consolidated financial statements.

On July 27, 2011, the Company completed the purchase of the Adena Properties.  The acquisition consists of an 80% working interest in 18,760 gross acres, with a net purchase price of $15.24 million.  The effective date of the acquisition is May 1, 2011.  The Company will operate the Adena Properties.  The Company has entered into an agreement with a strategic partner which will provide geological, engineering, and management services associated with this project and will earn 24% of the Company’s 80% working interest after payout of all costs, including financing costs.  The Adena Properties consist of an existing waterflood in the J Sand, and a conventional oil field in the D Sand.  In addition, there is a gas cap in the J Sand that can be produced in the future.

On July 27, 2011, in order to finance the acquisition of the Adena Properties, the Company entered into the Note Purchase Agreement with Carlyle.  Pursuant to the Note Purchase Agreement, the Company closed on the issuance and sale of Tranche A Notes in the aggregate principal amount of $18.0 million and Tranche B Notes in the aggregate principal amount of $2.5 million The Tranche A Notes mature and are due and payable on July 27, 2016.  They bear interest at a stated rate of 13% per annum, of which 10% must be paid in cash, and, at the election of the Company, 3% may be paid in cash or paid in kind and capitalized into the Tranche A Notes.  The Tranche B Notes bear a stated interest rate of 13% per annum, all of which is payable in kind and capitalized into the Tranche B Notes.

Subject to certain conditions, the Company can voluntarily prepay the Tranche A Notes.  If the Company prepays the Tranche A Notes before July 27, 2014, subject to certain exceptions, the Company must pay a “make-whole” amount, equal to the present value at the time of the prepayment of the amount of interest which would have been payable on the principal balance of the Tranche A Notes through July 31, 2014.

The Company may prepay the Tranche B Notes only in whole, and upon prepayment, the Company must pay a “make-whole” amount, equal to $1.2 million less the amount of paid in kind interest that has been capitalized into the note as of such date.

As additional consideration for the issuance of the Senior Secured Notes, the Company conveyed to the holders of the Senior Secured Notes overriding royalty interests equal to 3% of 8/8ths in the Adena Properties and agreed to convey overriding royalty interests in certain additional oil and gas properties acquired by the Company during the term of the Note Purchase Agreement.

The Senior Secured Notes are collateralized by substantially all of the assets of the Company.  The Senior Secured Notes are subject to customary events of default.  Upon the occurrence of an event of default, as described in the Note Purchase Agreement, the payment of the principal amounts under the Senior Secured Notes may be accelerated and the interest rate applicable to the principal amounts will be increased to a stated interest rate of 16% per annum during the period the default exists.

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The Company received approximately $18.0 million from the sale of the Senior Secured Notes, of which approximately $17.0 million was used for the acquisition of the Adena Properties and for related acquisition and financing costs and fees. The balance of approximately $1.0 million is to be used according to a plan of development for the Adena Properties that is subject to approval by Carlyle.

As of September 30, 2011, we had $18.85 million outstanding under the Amended Debenture. Under the Amended Debenture as amended to date: (i) the maturity date is January 15, 2014, (ii) interest is payable to WCOF on any outstanding principal at a rate equal to five percent (5%) per annum payable in shares of common stock of the Company in an amount based on a share price of $2.00 per share (the “Stock Interest”) and (iii) additional interest is payable to WCOF on any outstanding principal at a rate equal to five percent (5%) per annum payable in cash (the “Cash Interest”).  The Stock Interest is due and payable to WCOF quarterly in arrears on the last day of each calendar quarter, commencing with the calendar quarter ending on December 31, 2010. The Cash Interest is due and payable to WCOF on the maturity date of the Amended Debenture, less $5,000 per well drilled under the Farmout Agreement, which will be paid to WCOF upon the Company’s receipt of well-site fees from Atlas in accordance with the Farmout Agreement.  Additionally, the Company and WCOF have agreed that no event of default shall occur on the Amended Debenture until written notice of default is given to the Company by WCOF and such default shall have continued for a period of 30 days after written notice is delivered to the Company. WCOF agreed to subordinate the payment obligations under the Amended Debenture and related security interests to the payment obligations arising under the Senior Secured Notes and the security interests securing payment of the Senior Secured Notes pursuant to the terms and conditions of an intercreditor and subordination agreement.   As further security for the payment of the Senior Secured Notes, WCOF pledged to Carlyle all of its shares of stock in the Company. The intercreditor agreement provides that WCOF may buy out the Tranche A Notes from Carlyle upon an event of default by the Company.  For additional information on the Amended Debenture, see Note 6 to the accompanying condensed consolidated financial statements.

Results of Operations

The financial information with respect to the three and nine months ended September 30, 2011 and 2010, respectively, which is discussed below, is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, necessary for a fair presentation of the results for such periods. The results of operations for interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Three Months Ended September 30, 2011 (unaudited) Compared to the Three Months Ended September 30, 2010 (unaudited)

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Oil and Gas Sales

Oil and natural gas sales for the three months ended September 30, 2011 increased $379,000, or 332.5%, compared to the three months ended September 30, 2010 as a result of an increase in the volume of oil sold and an increase in natural gas prices, partially offset by a decrease in the volume of natural gas sold.   Oil sales, due to acquisition of the Adena Properties, were 5,008 barrels, or Bbls, for total revenue of $397,000 for the three months ended September 30, 2011.  Natural gas sales volumes decreased during the three months ended September 30, 2011 by 8,035 Mcf (or thousand cubic feet), from 32,730 Mcf for 2010 to 24,695 Mcf for 2011, resulting in a decrease in revenue of $30,000 for the three months ended September 30, 2011 compared to the three months ended September 30, 2010.   The average natural gas sales price during the three months ended September 30, 2011 was $0.39 per Mcf higher than the average natural gas sales price for the three months ended September 30, 2010 ($3.87 for 2011 compared to $3.48 for 2010) resulting in an increase in revenue of $12,000.

Gain on Sale of Oil and Gas Properties

During the three months ended September 30, 2011, the Company recognized a gain of $836,000 on the sale of proved well sites to Atlas as part of the Farmout Agreement.

Oil and Gas Production Expense

Oil and gas lease operating expense in the third quarter of 2011 decreased $89,000, or 29.7%, to $211,000 from $300,000 in the third quarter of 2010.   The decrease is a result of the Farmout Agreement, which includes provisions for allocating and billing operating expenses to Atlas.

Depreciation, Depletion, Amortization and Accretion (“DD&A”)

DD&A expense for the third quarter of 2011 increased $44,000, or 100.0%, to $88,000 from $44,000 in the third quarter of 2010 as a result of the increase in oil and gas production in 2011.

General and Administrative Expense

General and administrative expense for the third quarter of 2011 increased by $185,000, or 40.0%, to $648,000 from $463,000 for the third quarter of 2010.  The increase is primarily a result of the $277,000 general and administrative expense related to the Adena Properties acquisition.

Interest and Other Income

Interest and other income for the third quarter of 2011 increased $15,000 to $19,000 from $4,000 for the third quarter of 2010.

Gain on Derivative Contracts

During the three months ended September 30, 2011, the Company realized a gain of $57,300 on the cash settlement of derivative oil contracts, and recorded an unrealized gain of $1,122,700 from changes in fair value of derivative contracts, for a total realized and unrealized gain of $1,180,000.

Interest Expense

Interest expense for the third quarter of 2011 increased $961,000, or 658.2%, to $1,107,000 from $146,000 for the third quarter of 2010.  This increase is due to the issuance of the Senior Secured Notes to fund the Adena Properties Acquisition.

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Nine Months Ended September 30, 2011 (unaudited) Compared to the Nine Months Ended September 30, 2010 (unaudited)