UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2010

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-32471

BLACK RAVEN ENERGY, INC.

(Exact Name of Registrant as Specified in its Charter)

Nevada		20-0563497
(State or Other Jurisdiction		(I.R.S. Employer
of Incorporation or Organization)		Identification No.)

1125 Seventeenth Street, Suite 2300
Denver, CO		80202
(Address of Principal Executive Offices)		(Zip Code)

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 o No x

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 o 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.

Large accelerated filer o		Accelerated filer o

Non-accelerated filer o		Smaller reporting company x
(Do not check if a smaller reporting company)

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 November 15, 2010 was 16,658,109.

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TABLE OF CONTENTS

PART I — Financial Information		1
Item 1.	Financial Statements	1
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
Item 4T.	Controls and Procedures	19
PART II — Other Information		19
Item 1.	Legal Proceedings	19
Item 1A.	Risk Factors	20
Item 5.	Other information	20
Item 6.	Exhibits	20
	Signatures	21

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

Black Raven Energy, Inc. (formerly known as PRB Energy, Inc.)

Condensed Consolidated Balance Sheets

(Unaudited)

(In thousands)

	September 30, 2010			December 31, 2009
Assets
Current assets:
Cash and cash equivalents	$	414		$	1,064
Cash, restricted	941			—
Accounts receivable, net	86			62
Inventory	53			62
Prepaid expenses	95			108
Total current assets	1,589			1,296
Oil and gas properties accounted for under the successful efforts method of accounting:
Proved properties	5,248			4,626
Unproved leaseholds	4,595			5,842
Wells-in-progress	63			483
Total oil and gas properties	9,906			10,951
Less: Accumulated depreciation, depletion and amortization	(1,241		)	(1,212		)
Net oil and gas properties	8,665			9,739
Gathering and other property and equipment	2,983			2,964
Less: Accumulated depreciation and amortization	(986		)	(925		)
Net gathering and other property and equipment	1,997			2,039
Other non-current assets:
Deferred debt issuance costs, net	194			247
Other	100			96
Total other non-current assets	294			343
TOTAL ASSETS	$	12,545		$	13,417

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

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Black Raven Energy, Inc. (formerly known as PRB Energy, Inc.)

Condensed Consolidated Balance Sheets (Continued)

(Unaudited)

(In thousands)

	September 30, 2010			December 31, 2009
Liabilities and Stockholders’ Deficit
Current liabilities:
Accounts payable	$	472		$	238
Short-term borrowings from affiliate	250			—
Advances from Atlas (Note 4)	660			—
Accrued expenses and other current liabilities	162			308
Total current liabilities	1,544			546
Senior secured debentures, net of discount	18,848			17,828
Asset retirement obligation	235			219
Investment in insolvent subsidiary	—			1,072
Total liabilities	20,627			19,665
Commitments and Contingencies (Note 9)
Stockholders’ deficit
Common stock, par value $.001; 150,000,000 shares authorized; 16,658,109 and 16,660,965 issued and outstanding, respectively	17			17
Additional paid-in-capital	29,683			29,441
Accumulated deficit	(37,782		)	(35,706		)
Total stockholders’ deficit	(8,082		)	(6,248		)
TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT	$	12,545		$	13,417

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

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Black Raven Energy, Inc. (formerly known as PRB Energy, Inc.)

Condensed Consolidated Statements of Operations

(Unaudited)

(In thousands, except share and per share amounts)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009

Revenue:
Natural gas sales	$	114		$	97		$	344		$	330
Total revenue	114			97			344			330
Operating expenses:
Natural gas production expense	300			145			608			460
Exploration expense	—			—			11			4
Depreciation, depletion, amortization and accretion	44			54			112			197
General and administrative	463			698			1,670			1,387
Total operating expenses	807			897			2,401			2,048
Operating loss	(693		)	(800		)	(2,057		)	(1,718		)
Other income (expense):
Interest and other income	4			9			7			9
Loss on disposal of assets and other	—			—			(6		)	—
Interest expense	(146		)	(439		)	(1,085		)	(1,183		)
Total other expense	(142		)	(430		)	(1,084		)	(1,174		)
Loss before reorganization items and income taxes	(835		)	(1,230		)	(3,141		)	(2,892		)
Reorganization items:
Gain on reorganization	—			—			1,069			24,208
Loss on disposal of assets and other	—			—			—			(4		)
Professional fees	—			(13		)	(4		)	(133		)
Interest on accumulated cash in bankruptcy	—			1			—			1
Total reorganization items	—			(12		)	1,065			24,072
Net income (loss) before income taxes	(835		)	(1,242		)	(2,076		)	21,180
Income tax provision/benefit	—			—			—			—
Net income (loss)	$	(835	)	$	(1,242	)	$	(2,076	)	$	21,180
Net income (loss) per common share—basic and diluted	$	(0.05	)	$	(0.08	)	$	(0.12	)	$	1.46
Basic and diluted weighted average shares outstanding	16,658,109			15,818,574			16,658,507			14,555,399

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

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Black Raven Energy, Inc. (formerly known as PRB Energy, Inc.)

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(In thousands)

	Nine Months Ended
	September 30,
	2010			2009
Cash flows from operating activities
Net income (loss)	$	(2,076	)	$	21,180
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation, depletion, amortization and accretion	112			197
Amortization of debt issuance costs	53			—
Amortization of discount on debentures	672			853
Share-based compensation expense	242			269
Gain on reorganization	(1,069		)	(24,208		)
Loss on disposal of assets and other	6			4
Changes in assets and liabilities:
Restricted cash	(941		)	—
Accounts receivable	(24		)	42
Inventory	9			(19		)
Prepaid expenses	13			241
Other non-current assets	(4		)	(22		)
Accounts payable	205			(721		)
Advances from Atlas	660			—
Accrued expenses and other current liabilities	202			(300		)
Net cash used in operating activities	(1,940		)	(2,484		)
Cash flows from investing activities
Capital expenditures	(320		)	(310		)
Proceeds from Farmout Agreement (Note 4)	1,360			—
Proceeds from sale of assets	—			1
Net cash provided by (used in) investing activities	1,040			(309		)
Cash flows from financing activities
Proceeds from loans from affiliate	250			—
Proceeds from senior secured debentures	—			1,500
Proceeds from issuance of common stock	—			3,500
Repayment of loans	—			(911		)
Net cash provided by financing activities	250			4,089
Net increase (decrease) in cash	(650		)	1,296
Cash—beginning of year	1,064			472
Cash and cash equivalents—end of year	$	414		$	1,768
Supplemental disclosure of cash flow activity
Cash paid for interest	$	117		$	427
Supplemental schedule for non-cash activity
Accrued capital expenditures	$	33		$	3
Conversion of interest to debt	$	348		$	546

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

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BLACK RAVEN ENERGY, INC. (formerly known as PRB ENERGY, INC.)

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

Description of Business

Black Raven Energy, Inc. (“Black Raven,” the “Company,” “us,” “our” or “we”), formerly known as PRB Energy, Inc. (“PRB Energy”), operates 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, PRB Energy and its subsidiaries filed voluntary petitions for relief for each business entity (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”). PRB Energy 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 PRB Energy’s and PRB Oil and Gas, Inc.’s (“PRB Oil”), a wholly-owned subsidiary of PRB Energy, Modified Second Amended Joint Plan of Reorganization (the “Plan”). The effective date of the Plan was deemed to be February 2, 2009 (the “Effective Date”). Pursuant to the Plan, all 8,721,994 shares of PRB Energy’s common stock were cancelled and PRB Energy changed its corporate name to Black Raven Energy, Inc. The Plan provided that we continue as a public company following our emergence from bankruptcy and for the issuance of new common stock of Black Raven to certain claimants, with such new common stock to be traded on the OTC Bulletin Board or a nationally recognized securities exchange, subject to compliance with applicable regulations. After the effective date, PRB Oil was merged into the Company.

We deconsolidated PRB Gathering, Inc. (“PRB Gathering”), a wholly-owned subsidiary of PRB Energy, during the fourth quarter of 2008. Effective November 1, 2008, control of the Recluse Gathering System was turned over to a receiver appointed by the State Court of Wyoming. The Company’s investment/obligation with regard to the PRB Gathering business is reflected as an Investment in Insolvent Subsidiary in the accompanying balance sheet as of December 31, 2009. PRB Gathering emerged from Chapter 11 Bankruptcy on February 17, 2010 and a gain on reorganization was recognized for the amount of the Company’s obligation for PRB Gathering.

The accompanying financial statements have been prepared assuming the Company will continue as a going concern. As shown in the accompanying Unaudited Condensed Consolidated Financial Statements, the Company continues to experience net losses from operations, reporting a net loss before reorganization items of approximately $3.1 million for the nine months ended September 30, 2010. Cash and cash equivalents on hand and internally generated cash flows will not be sufficient to execute the Company’s business plan. Future bank financings, asset sales, or other equity or debt financings will 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.

During the quarter ended September 30, 2010, the Company entered into a Farmout Agreement, dated July 23, 2010 (the “Farmout Agreement”) with Atlas Resources, LLC (“Atlas”), as further discussed in Note 4. The Farmout Agreement is expected to provide the Company sufficient cash flow to commence drilling operations on the properties subject to the agreement and to meet working capital requirements. The Company will explore other opportunities to raise capital as needed to fund its debt service, potential acquisitions and other capital expenditures. There can be no assurances that the Company will be able to secure additional financing if and when necessary.

Basis of Presentation

The accompanying Unaudited Condensed Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information. Pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying Unaudited Condensed Consolidated Financial Statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the Company’s financial position as of September 30, 2010, the Company’s results of operations for the three and nine months ended September 30, 2010 and 2009, and cash flows for the nine months ended September 30, 2010 and 2009. Operating results for the three and nine months ended September 30, 2010 are not necessarily indicative of the results that may be

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expected for the full year because of the impact of fluctuations in prices received for natural gas and oil, natural production declines, the uncertainty of exploration and development drilling results and other factors. For a more complete understanding of the Company’s operations, financial position and accounting policies, the Unaudited Condensed Consolidated Financial Statements and the notes thereto should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 previously filed with the SEC.

For the period from March 5, 2008 through the Effective Date, we conducted our business in the ordinary course as debtors-in-possession under the protection of the Bankruptcy Court. We emerged from Chapter 11 Bankruptcy on February 2, 2009. Our Condensed Consolidated Financial Statements have been prepared in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 852, “Reorganizations” (“ASC Topic 852”), which requires financial statements for periods subsequent to our Chapter 11 Bankruptcy filings to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain income, expenses, realized gains and losses and provisions for losses that were realized or incurred in our Chapter 11 Bankruptcy cases are recorded in reorganization items on our Condensed Consolidated Statements of Operations. We determined that we did not meet the requirements to adopt fresh start accounting on the Effective Date of our emergence from Chapter 11 Bankruptcy because the reorganization value of our assets exceeded the total of post-petition liabilities and allowed claims. See Note 3 for further discussion of the Plan and the applicability of fresh start accounting.

Summary of Significant Accounting Policies

Use of Estimates - The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Some specific examples of such estimates include the allowance for accounts receivable, accrued expenses, accrued revenue, asset retirement obligations, determining the remaining economic lives and carrying values of property and equipment and the estimates of gas reserves that affect the depletion calculations and impairments for gas properties and other long-lived assets. In addition, we use assumptions to estimate the fair value of share-based compensation. We believe our estimates and assumptions are reasonable; however, actual results may differ from our estimates.

Cash and Cash Equivalents - We consider all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. We continually monitor our positions with, and the credit quality of, the financial institutions with which we invest.

Restricted Cash — Restricted cash includes advances from Atlas restricted for drilling activities in connection with oil and gas properties subject to the Farmout Agreement. See Note 4 for further discussion of Farmout Agreement.

Income Taxes - We recognize deferred tax liabilities and assets based on the differences between the tax basis of assets and liabilities and their reported amounts in the consolidated financial statements that will result in taxable or deductible amounts in future years. In evaluating the ability to realize net deferred tax assets, we will take into account a number of factors, primarily relating to our ability to generate taxable income. We have recognized, before the valuation allowance, a net deferred tax asset attributable to the net operating losses as of September 30, 2010 and December 31, 2009. FASB ASC Topic 740, “Income Taxes” (“ASC Topic 740”), requires that a valuation allowance be recorded against deferred tax assets unless it is more likely than not that the deferred tax asset will be utilized. As a result of this analysis, we have recorded a full valuation allowance against the Company’s net deferred tax asset.

The Company has adopted the uncertainty provisions of ASC Topic 740, which requires the Company to recognize the impact of a tax position in its financial statements only if the technical merits of that position indicate that the position is more likely than not of being sustained upon audit. We recognize potential accrued interest and penalties, if any, related to unrecognized tax benefits in income tax expense, which is consistent with the recognition of these items in prior reporting periods. Due to the significant net operating losses, no interest and penalties were accrued.

Revenue Recognition - Revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if the collectability of the revenue is probable. We derive revenue from the sale of produced natural gas. We report revenue at the gross amount received before taking into account production taxes and transportation costs, which are reported as separate expenses. Revenue is recorded in the month our production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. Revenues from the production of gas properties in which we have an interest with other producers are recognized on the basis of our net working interest. At the end of each month, we calculate a revenue accrual based on the estimates of production delivered to or transported for the purchaser.

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Property and Equipment - Gas Gathering and Other - Gathering assets, including compressor sites and pipelines, are recorded at cost and depreciated using the straight line method over 10 years. Other property and equipment, such as office furniture, computer and related software and equipment, automobiles and leasehold improvements are recorded at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets or underlying leases, in respect to leasehold improvements, ranging from three to ten years.

Oil and Gas Producing Properties - We have elected to follow the successful efforts method of accounting for our oil and gas properties. Under this method of accounting, 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 unsuccessful exploratory well are charged to expense. Exploratory dry hole costs are included in cash flows from investing activities as part of capital expenditures in the consolidated statements of cash flows. The cost of development wells, whether productive or not, is capitalized.

Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive and are assigned proved reserves. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognizing gain until all costs are recovered. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

Depreciation, depletion and amortization (“DD&A”) of capitalized costs of proved oil and gas properties is determined on a field-by-field basis using the units-of-production method based upon proved reserves. The computation of DD&A takes into consideration restoration, dismantlement and abandonment costs and the anticipated proceeds from equipment salvage.

Impairment of Long-Lived Assets - In accordance with FASB ASC Topic 360, “Property, Plant and Equipment” (“ASC Topic 360”), we group assets at the field level and periodically review the carrying value of our property and equipment to test whenever current events or circumstances indicate that such carrying value may not be recoverable. If the tests indicate that the carrying value of the asset is greater than the estimated future undiscounted cash flows to be generated by such asset, an impairment adjustment will be recognized. Such adjustment consists of the amount by which the carrying value of such asset exceeds its fair value. We generally measure fair value by considering sale prices for similar assets or by discounting estimated future cash flows from such asset using an appropriate discount rate. Considerable management judgment is necessary to estimate the fair value of assets, and accordingly, actual results could vary significantly from such estimates.

Discount of Debt - On February 2, 2009, we issued an Amended and Restated Senior Secured Debenture payable to West Coast Opportunity Fund, LLC (“WCOF”) in the amount of $18,450,000 (the “Amended Debenture”). We recorded a $1.4 million discount on the Amended Debenture in the first quarter of 2009. The discount on the Amended Debenture was amortized using the retrospective interest method and is fully amortized at September 30, 2010. The discount is included in the balance of the Amended Debenture at December 31, 2009.

Net Loss Per Share - We account for earnings (loss) per share (“EPS”) in accordance with FASB 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 outstanding warrants and in-the-money outstanding stock options to purchase our common stock for the periods ended September 30, 2010 and December 31, 2009. 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 periods ended September 30, 2010 and 2009, there were no potentially dilutive securities outstanding whose effect would be dilutive to our earnings per share calculation.

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

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	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2010	2009	2010	2009
Warrants	1,494,298	1,494,298	1,494,298	1,494,298
Options	1,532,500	1,232,500	1,532,500	1,232,500
Total potentially dilutive shares excluded	3,026,798	2,726,798	3,026,798	2,726,798

Subsequent to September 30, 2010, we did not issue any dilutive securities which would have increased the number of potentially dilutive shares.

Comprehensive Income (Loss) - We account for comprehensive income (loss) in accordance with FASB ASC Topic 220, “Comprehensive Income” (“ASC Topic 220”), which established standards for the reporting and presentation of comprehensive income (loss) in our consolidated financial statements. For the nine months ended September 30, 2010 and 2009, comprehensive loss is equal to net loss as reported in our Condensed Consolidated Statement of Operations.

Off-Balance Sheet Arrangements — We have not participated in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance or special purpose entities (“SPEs”), or SPEs which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As of September 30, 2010, the Company is not involved in any off-balance sheet arrangements.

Fair Value of Financial Instruments - Our financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and secured debentures, are carried at cost. At September 30, 2010, the fair value of the cash and cash equivalents, accounts receivable, and accounts payable approximates carrying value due to the short term nature of these instruments. The fair value of our debentures at September 30, 2010 is approximately $18.9 million, based on a discounted cash flow model using expected future cash flows.

Concentrations of Credit Risk - Revenues from customers which represented 10% or more of our gas sales for the three and nine months ended September 30, 2010 and 2009, respectively, were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
Customer	2010		2009		2010		2009
	(% of total revenue)				(% of total revenue)
A — Exploration and Production	75	%	64	%	70	%	75	%
B — Exploration and Production	25	%	36	%	30	%	25	%

Industry Segment and Geographic Information - The Company operates in one industry segment, which is the exploration, development and production of natural gas and crude oil, and all of the Company’s operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment.

Note 2—Recent Accounting Pronouncements

In January 2010, the FASB issued ASC Update 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends Accounting Standards Codification 820, “Fair Value Measurements and Disclosures” (“ASC Update 2010-06”), that 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 the 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 will be effective for the Company as of January 1, 2011. The adoption of ASC Update 2010-06 did not have and is not expected to have a material impact on the Company’s consolidated financial statements.

The Company adopted FASB ASC Update 2010-09, “Subsequent Events-Amendments to Certain Recognition and Disclosure Requirements,” which removes the requirement for SEC filers to disclose the date through which an entity has evaluated subsequent events. However, the date-disclosure exemption does not relieve management of an SEC filer from its responsibility to evaluate subsequent events through the date on which financial statements are issued. This authoritative

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guidance was effective upon issuance on February 24, 2010. The adoption of this pronouncement did not have a material impact on the Company’s consolidated financial statements.

Note 3—Emergence from Chapter 11 Bankruptcy

On January 16, 2009, the Bankruptcy Court entered an order confirming the Plan, with an effective date of February 2, 2009. Pursuant to the Plan, all 8,721,994 outstanding shares of PRB Energy’s common stock were cancelled and PRB Energy changed its corporate name to Black Raven Energy, Inc. The Plan provided that we continue as a public company following our emergence from bankruptcy and for the issuance of new common stock of Black Raven to certain claimants.

Pursuant to the terms of the Plan, the Company issued 1,419,339 shares of common stock, along with one warrant for each share at an exercise price of $2.50 per share, on a pro-rata basis to the holders of our previously outstanding convertible notes. The Company issued an additional 74,959 shares of common stock, along with one warrant for each share at an exercise price of $2.50 per share, on a pro-rata basis to the other claimants related to accounts payable, accrued expenses and other current liabilities. The Company also issued 13.5 million shares of common stock to WCOF, the principal pre-petition secured creditor.

After the effective date of the Plan, PRB Oil was merged into the Company. We deconsolidated PRB Gathering during the fourth quarter of 2008. Effective November 1, 2008, control of the Recluse Gathering System was turned over to a receiver appointed by the State Court of Wyoming. PRB Gathering emerged from Chapter 11 Bankruptcy on February 17, 2010.

Note 4—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 a Company facility. The Company assigned to Atlas all of its rights, title and interests in the defined areas around the planned wellbores (the “Drilling Units”) for the Initial Wells. As of September 30, 2010, drilling of The Initial Wells has been completed.

The Farmout Agreement also provides for Atlas, at its discretion, to drill additional wells in the AMI in accordance with work plans approved by Atlas under the Farmout Agreement (each a “Work Plan”). The initial Work Plan approved by Atlas covering the period from July 23, 2010 to April 30, 2011 provides for Atlas, at its discretion, to drill 60 additional 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 and delivery of an executed authorization for expenditure (AFE) for such well by Atlas, the Company will assign all of its right, 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 of drilling and future 3D seismic costs.

In consideration for the agreements made under the Farmout Agreement, Atlas paid the Company $1,000,000 upon execution of the Farmout Agreement. Such amount has been shown as a recovery of the cost of the Company’s proved and unproved oil and gas properties, as applicable. 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, 2010, the Company had received $360,000 as well site fees for the Initial Wells, which are also shown as a recovery of the cost of the Company’s oil and gas properties. The Company will recognize gains on any well-site fees received for future drilling under the Farmout Agreement at such time that all costs related to the oil and gas properties subject to the Farmout Agreement have been recovered.

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.

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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. To date, Atlas has funded and drilled the six Initial Wells and the Company has accrued a liability pursuant to the advisory fee agreement of $60,000 for the Initial Wells in the accompanying Condensed Consolidated Balance Sheet as of September 30, 2010.

Note 5—Asset Retirement Obligation

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 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 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. The credit-adjusted risk-free rate used to discount the Company’s abandonment liabilities is ten percent. 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:

	Nine Months Ended
	September 30,
	2010		2009
	(in thousands)
Asset retirement obligations, beginning of period	$	219	$	345
Liabilities incurred	—		—
Liabilities settled	—		—
Sale of assets	—		—
Accretion expense	16		17
Revision to estimated cash flows	—		—
Asset retirement obligations, end of period	$	235	$	362

Note 6—Borrowings

As of September 30, 2010 and December 31, 2009, our borrowings consisted of the following:

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	September 30,		December 31,
	2010		2009
	(in thousands)
Amended senior secured debentures	$	18,848	$	18,500
Less discount	—		(672		)
Total borrowings, net of discount	18,848		17,828
Less current portion	—		—
Total borrowings, net of discount and current portion	$	18,848	$	17,828

Amended and Restated Senior Secured Debentures

On February 2, 2009, in connection with the consummation of the Plan, we, along with our subsidiary PRB Oil, entered into a Modification Agreement with WCOF. Under the Modification Agreement, we issued the Amended Debenture, payable to WCOF in the amount of $18.45 million. The Amended Debenture superseded and amended the senior secured debentures issued by PRB Oil to WCOF and DKR Soundshore Oasis Holding Fund Ltd. on December 28, 2006. Under the terms of the Amended Debenture, $3.75 million of the outstanding principle balance and unpaid accrued interest were initially due on December 31, 2009, with the remainder of the outstanding balance and unpaid accrued interest due on December 31, 2010. The Amended Debenture accrued interest at 10% per annum payable quarterly.

On April 13, 2009, Black Raven, WCOF and the Official Committee of Unsecured Creditors Appointed by the Bankruptcy Court entered into an Agreement Regarding New Equity Raise Under the Modified Second Amended Joint Plan of Reorganization (the “New Equity Agreement”). The New Equity Agreement modified the obligations of the parties under the Plan and released WCOF from its obligation to raise or guarantee $7.5 million of additional funding for us. The New Equity Agreement required WCOF to purchase 166,667 shares of the New Common Stock from us for $3.00 per share within 10 business days of the New Equity Agreement and an additional $3 million of New Common Stock, preferred stock or convertible debt securities from time to time prior to September 10, 2010, at a purchase price of $2.00 per share. The New Equity Agreement also modified the interest rate under the Amended Debenture and extended the maturity date of the Amended Debenture to December 31, 2011.

On November 9, 2009, the Amended Debenture was amended to increase the principal amount to $18.5 million in lieu of paying $50,000 in interest to WCOF.

On January 10, 2010, WCOF agreed to extend the due date for all principal payments in connection with the Amended Debenture to June 30, 2013 subject to the Company raising $25 million in new equity by February 10, 2010. The Company did not raise the required capital. Therefore, the due date for all principal payments remains December 31, 2011.

On July 23, 2010, the Company and WCOF entered into the Third Amendment to the Amended Debenture (the “Third Amendment”). Pursuant to the terms of the Third Amendment, the Amended Debenture was amended as follows: (i) all current unpaid and accrued interest was added to the outstanding principal balance of the Amended Debenture, (ii) for the period from July 1, 2010 through December 31, 2011, the Company will not be required to make any payments of accrued interest on the Amended Debenture and such accrued interest will be added to the outstanding principal balance, and (iii) 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.

On October 12, 2010, the Company and WCOF entered into the Fourth Amendment to the Amended Debenture (the “Fourth Amendment”). Pursuant to the terms of the Fourth Amendment, the Amended Debenture was amended as follows: (i) the maturity date was extended to January 15, 2014, (ii) interest will be paid on any outstanding Principal to WCOF 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 will be paid on any outstanding Principal to WCOF at a rate equal to five percent (5%) per annum payable in cash (the “Cash Interest”). The Stock Interest shall be 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 shall be due and payable to WCOF on the Maturity Date of the Debenture, offset by $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 agreed that no event of default shall occur on the Amended

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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.

As the stated rate at which the Company currently pays interest is not a prevailing rate at which the Company could obtain third party financing, the Company has calculated and recorded its obligation under the Amended Debenture at a discount in the accompanying Condensed Consolidated Balance Sheets. Due to the variable nature of the interest to be paid under the Amended Debenture, the Company uses the retrospective method to amortize its discount and impute interest on the Amended Debenture. For the three months and nine months ended September 30, 2010, the Company has recorded $0 and $672,000 of interest expense, respectively, related primarily to the amortization of the discount on its Amended Debenture. The interest expense for the three and nine months ended September 30, 2009 was $320,000 and $853,000, respectively.

Short-Term Borrowings from Affiliate

The Company received a cash advance from WCOF on May 27, 2010 in the amount of $150,000. An additional cash advance of $100,000 was made from WCOF on July 2, 2010. Both advances, plus accrued interest at 10% per annum from the date of each advance, are due within thirty days of the Company’s receipt of the cash payment for the Well-Site Fees (as defined in the Farmout Agreement) related to the first sixty wells drilled under the Farmout Agreement.

PRB Funding Prepetition Loan

Immediately prior to the filing of the Chapter 11 petitions, the Company borrowed $300,000 from PRB Funding, LLC (“PRB Funding”) due on February 28, 2009. PRB Funding was formed by three members of our Board of Directors. The PRB Funding Loan was secured by substantially all of the assets of PRB Energy and was repaid in 2009.

Post-Petition Debtor-in-Possession Financing

In April 2008, the Company obtained court approval of post-petition Debtor-in-Possession Financing (“DIP Loan”) from PRB Funding in the amount of $275,000. The PRB Funding DIP Loan accrued interest at 13% per annum, with all unpaid principal and accrued interest due upon the earlier of March 1, 2009 or the confirmation of the Plan.

In May 2008, the Company obtained court approval of a $336,000 post-petition DIP Loan from PRB Acquisition, an entity that was affiliated with Republic Financial. The PRB Acquisition DIP Loan accrued interest at 18% per annum, with all unpaid principal and accrued interest due upon the earliest of September 30, 2008, an event of default, or the confirmation of a plan of reorganization.

Both DIP Loans were repaid in 2009.

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, 2010 and 2009 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 and the Company’s valuation allowance. The Company’s effective tax rate for the three months ended September 30, 2010 and 2009, before valuation allowance, was 37.95% and 36.06%, respectively. The Company’s effective tax rate for the nine months ended September 30, 2010 and 2009, before valuation allowance, was 37.94% and 36.06%, respectively.

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, 2010. The Company’s evaluation of the amount of the deferred tax asset considered more likely than not to

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be realizable may 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. During the nine months ended September 30, 2010, there was no change to the Company’s liability for uncertain tax positions.

Note 8—Equity Compensation Plan

On June 3, 2009, the Board 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.

On July 1, 2009, the Company issued 1,060,000 stock options to employees of the Company under the Equity Compensation Plan. The options have an exercise price of $2.00 per share for a total fair value of $1.1 million and vest ratably over three years. The Company issued the same employees an additional 172,500 stock options on September 16, 2009, which vested immediately. The options have an exercise price of $2.00 per share, and a total fair value of $178,000. On December 8, 2009, the Company issued 100,000 options to two directors. The options have an exercise price of $2.00 per share, and a total fair value of $64,000.

On February 7, 2010, the Company issued 100,000 options to an officer of the Company. The options have an exercise price of $2.00 per share, a total fair value of $59,000 and vests over three years. The Company recorded equity compensation expense for the three and six months ended June 30, 2010 totaling $65,000 and $120,000, respectively, related to vesting of the 2009 and 2010 grants. On August 26, 2010, the Company issued 100,000 options to two directors. The options have an exercise price of $2.00 per share, and a total fair value of $61,500.

Note 9 —Commitments and Contingencies

Commitments

In the normal course of business operations, the Company has entered into operating leases for office space, office equipment and vehicles. Rental payments under these operating leases for the three months ended September 30, 2010 and 2009 totaled $31,000 and $19,000, respectively. Rental payments for the nine months ended September 30, 2010 and 2009 totaled $82,000 and $77,000, respectively.

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

Forward-Looking Statements

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

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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 Annual Report on Form 10-K for the year ended December 31, 2009.

General Overview and Significant Transactions

Black Raven Energy, Inc (the “Company” or “we”), formerly known as PRB Energy, Inc. (“PRB Energy”), currently operates 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 February 2, 2009, in connection with our emergence from bankruptcy, PRB Energy changed its corporate name to Black Raven Energy, Inc.

The accompanying 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 before reorganization items of approximately $3.1 million for the nine months ended September 30, 2010. Cash and cash equivalents on hand and internally generated cash flows will not be sufficient to execute the Company’s business plan. Future bank financings, asset sales, or other equity or debt financings will 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.

During the quarter ended September 30, 2010, the Company entered into the Farmout Agreement as discussed below. The Farmout Agreement is expected to provide the Company sufficient cash flows to commence drilling operations on the properties subject to the agreement, from which the Company will receive an overriding royalty interest, and to meet working capital requirements. The Company will explore other opportunities to raise capital as needed to fund its debt service, potential acquisitions and other capital expenditures. There can be no assurances that the Company will be able to secure this additional financing if and when necessary.

Farmout Agreement

On July 23, 2010, the Company entered into a Farmout Agreement (the “Farmout Agreement”) with Atlas Resources, LLC, a wholly-owned subsidiary of Atlas Energy, Inc. (“Atlas”), 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, upgrade of sales meter equipment, and the change-out of compressors and upgrade of a dehydrator at a Company facility. The Company assigned to Atlas all of its rights, title and interests in the defined areas around the planned wellbores (the “Drilling Units”) for the Initial Wells. As of September 30, 2010, drilling of The Initial Wells has been completed.

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 of drilling and future 3D seismic costs.

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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. To date, Atlas has funded and drilled the six Initial Wells and the Company has accrued a liability pursuant to the advisory fee agreement of $60,000 for the Initial Wells in the accompanying condensed consolidated balance sheet as of September 30, 2010.

Emergence from Bankruptcy

Modified Debt Agreements

On February 2, 2009, in connection with the consummation of the Plan, we, along with our subsidiary PRB Oil, entered into a Modification Agreement with WCOF. Under the Modification Agreement, we issued the Amended Debenture, payable to WCOF in the amount of $18.45 million. The Amended Debenture superseded and amended the senior secured debentures issued by PRB Oil to WCOF and DKR Soundshore Oasis Holding Fund Ltd. on December 28, 2006. Under the terms of the Amended Debenture, $3.75 million of the outstanding principal balance and unpaid accrued interest were initially due on December 31, 2009, with the remainder of the outstanding balance and unpaid accrued interest due on December 31, 2010. The Amended Debenture accrued interest at 10% per annum payable quarterly.

On November 9, 2009, the Amended Debenture was amended to increase the principal amount to $18.5 million in lieu of paying $50,000 in interest to WCOF.

On January 10, 2010, WCOF agreed to extend the due date for all principal payments in connection with the Amended Debenture to June 30, 2013 subject to the Company raising $25 million in new equity by February 10, 2010. As the Company did not raise the required capital, the due date for all principal payments remains December 31, 2011.

On July 23, 2010, the Company and WCOF entered into the Third Amendment to the Amended Debenture. Pursuant to the terms of the Third Amendment, the Amended Debenture was amended as follows: (i) all current unpaid and accrued interest was added to the outstanding principal balance of the Amended Debenture, (ii) for the period from July 1, 2010 through December 31, 2011, the Company will not be required to make any payments of accrued interest on the Amended Debenture and such accrued interest will be added to the outstanding principal balance, and (iii) 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.

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maturity date was extended to January 15, 2014, (ii) interest will be paid on any outstanding Principal to WCOF 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 will be paid on any outstanding Principal to WCOF at a rate equal to five percent (5%) per annum payable in cash (the “Cash Interest”). The Stock Interest shall be 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 shall be due and payable to WCOF on the Maturity Date of the Debenture, offset by $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 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.

Results of Operations

Three Months Ended September 30, 2010 Compared to the Three Months Ended September 30, 2009

The financial information with respect to the three months ended September 30, 2010 and 2009, respectively, which is discussed below, is unaudited. The results of operations for interim periods are not necessarily indicative of the results of operations for the full fiscal year.

	Ended September 30,						Increase/			Percentage
	(In thousands)						Decrease			Change
	2010			2009			2010 vs 2009			2010 vs 2009
Revenue
Natural gas sales	$	114		$	97		$	17		17.5	%
Total revenue	114			97			17			17.5	%
Operating expenses
Natural gas production expense	300			145			155			106.9	%
DD&A	44			54			(10		)	-18.5	%
G&A	463			698			(235		)	-33.7	%
Total expenses	807			897			(90		)	-10.0	%
Operating loss	(693		)	(800		)	107			13.4	%
Interest and other income (loss)	4			9			(5		)	-55.6	%
Interest expense	(146		)	(439		)	293			66.7	%
Reorganization items and other	—			(12		)	12			100.0	%
Net loss	$	(835	)	$	(1,242	)	$	407		-32.8	%

Revenues

Natural gas sales for the third quarter of 2010 increased $17,000, or 17.5%, from $97,000 in the third quarter of 2009 to $114,000 in the third quarter of 2010 as a result of an increase in natural gas prices partially offset by a decrease in the volume of natural gas sold. The average sales price during the third quarter of 2010 was $.73 per Mcf higher than the average sales price for the third quarter of 2009 ($3.48 for 2010 compared to $2.75 for 2009) resulting in a revenue increase of $26,000. Sales volumes decreased in the third quarter of 2010 by 2,794 Mcf, from 35,524 Mcf for the third quarter of 2009 to 32,730 Mcf for the third quarter of 2010, causing a revenue decline of $9,000 for the third quarter of 2010 compared to the third quarter of 2009.

Natural Gas Production Expenses

Natural gas production expenses in the third quarter of 2010 increased $155,000, or 106.9%, to $300,000 from $145,000 in the third quarter of 2009 as a result of an increase in repairs and workover expenses incurred during the third quarter of 2010.

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

DD&A expense for the third quarter of 2010 decreased $10,000, or 18.5%, from $54,000 in the third quarter of 2009 to $44,000 in the third quarter of 2010 as a result of the decrease in gas production in 2010.

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General and Administrative Expenses (“G&A”)

G&A expenses for the third quarter of 2010 decreased by $235,000, or 33.7%, to $463,000 from $698,000 for the third quarter of 2009. This decrease was primarily due to a decrease in equity compensation expense. In addition, the Company received a $90,000 payment from Atlas for the reimbursement of overhead costs incurred by the Company in connection with the first six wells drilled under The Farmout Agreement, which further reduced general and administrative expenses.

Interest Expense

Interest expense for the third quarter of 2010 decreased $293,000, or 66.7%, to $146,000 from $439,000 for the third quarter of 2009. This decrease is attributable to the reduced amortization of the discount on the Amended Debenture which was fully amortized during the second quarter of 2010.

Nine Months Ended September 30, 2010 Compared to the Nine Months Ended September 30, 2009

The financial information with respect to the nine months ended September 30, 2010 and 2009, respectively, which is discussed below, is unaudited. The results of operations for interim periods are not necessarily indicative of the results of operations for the full fiscal year.

	Nine Months
	Ended September 30,						Increase/			Percentage
	(In thousands)						Decrease			Change
	2010			2009			2010 vs 2009			2010 vs 2009
Revenue
Natural gas sales	$	344		$	330		$	14		4.2	%
Total revenue	344			330			14			4.2	%
Operating expenses
Natural gas production expense	608			460			148			32.2	%
Exploration expense	11			4			7			175.0	%
DD&A	112			197			(85		)	-43.1	%
G&A	1,670			1,387			283			20.4	%
Total expenses	2,401			2,048			353			17.2	%
Operating loss	(2,057		)	(1,718		)	(339		)	-19.7	%
Interest and other income (loss)	7			9			(2		)	-22.2	%
Interest expense	(1,085		)	(1,183		)	98			8.3	%
Reorganization items and other	(10		)	(136		)	126			92.6	%
Gain on reorganization	1,069			24,208			(23,139		)	-95.6	%
Net income (loss)	$	(2,076	)	$	21,180		$	(23,256	)	-109.8	%

Revenues

Natural gas sales for the nine months ended September 30, 2010 increased $14,000, or 4.2%, in comparison to the nine months ended September 30, 2009 as a result of an increase in natural gas prices partially offset by a decrease in the volume of natural gas sold. The average sales price during the nine months ended September 30, 2010 was $1.18 per Mcf higher than the average sales price for the nine months ended September 30, 2009 ($4.01 for 2010 compared to $2.83 for 2009) resulting in a revenue increase of $137,000. Sales volumes decreased during the nine months ended September 30, 2010 by 30,601 Mcf, from 116,531 Mcf for the nine months ended September 30, 2009 to 85,930 Mcf for the nine months ended September 30, 2010, causing a revenue decline of $123,000 for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009.

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Natural Gas Production Expenses

Natural gas production expenses during the nine months ended September 30, 2010 increased $148,000, or 32.2%, to $608,000 from $460,000 for the nine months ended September 30, 2009 as a result of an increase in repairs and workover expenses incurred during 2010.

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

DD&A expense for the nine months ended September 30, 2010 decreased $85,000, or 43.1%, from $197,000 for the nine months ended September 30, 2009 to $112,000 for the nine months ended September 30, 2010 as a result of the decrease in gas production in 2010.

General and Administrative Expenses (“G&A”)

G&A expenses for the nine months ended September 30, 2010 increased by $283,000, or 20.4%, to $1,670,000 from $1,387,000 for the nine months ended September 30, 2009. This increase was primarily due to an increase in accounting, auditing and legal fees associated with the Company’s efforts to become current with its SEC and tax filing requirements, as well as the Company’s efforts to raise capital.

Gain on Reorganization

The Company’s obligation with regard to the PRB Gathering business was reflected as an investment in insolvent subsidiary in the accompanying balance sheet as of December 31, 2009. PRB Gathering emerged from Chapter 11 Bankruptcy on February 17, 2010 and a gain on reorganization of approximately $1.1 million was recognized.

During the nine months ended September 30, 2009, the Company recorded a gain on reorganization of approximately $24.2 million, related to PRB Energy’s emergence from bankruptcy effective February 2, 2009.

Interest Expense

Interest expense for the nine months ended September 30, 2010 decreased $98,000, or 8.3%, to $1,085,000 from $1,183,000 for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009. This decrease is attributable to the reduced amortization of the discount on the Amended Debenture.

Liquidity and Capital Resources

At September 30, 2010, cash and cash equivalents totaled approximately $414,000. At September 30, 2010, the Company had working capital of $45,000 compared to working capital of $750,000 at December 31, 2009. The decline is attributable to continued operating losses.

On July 23, 2010, the Company entered into the Farmout Agreement with Atlas. In consideration for the agreements made under the Farmout Agreement, Atlas paid the Company $1.0 million 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 under the Farmout Agreement. As of September 30, 2010, the Company had received $360,000 for the Initial Wells. 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 Farmout Agreement is expected to provide the Company sufficient cash flows to commence drilling operations on the properties subject to the agreement and to meet working capital requirements. Cash and cash equivalents on hand and internally generated cash flows will require augmentation from future bank financings, asset sales, or other equity or debt financing to fund our debt service, potential acquisitions and other capital expenditures. The Company will continue to explore opportunities to raise capital as needed, including through the sale of equity and debt securities. The Amended Debenture may restrict the Company from such capital raising activities. The amount and allocation of future capital and exploitation expenditures will depend upon a number of factors including the number and size of acquisitions and drilling opportunities, our cash flows from operating and financing activities and our ability to assimilate acquisitions. Also, the impact of oil and gas market prices on investment opportunities, the availability of capital and borrowing facilities and the success of our exploitation and development activities, particularly in Colorado, could lead to changes in funding requirements for future development. There can be no assurances that the Company will be able to secure this additional financing if and when necessary.

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Cash Flow Used in Operating Activities

During the nine months ended September 30, 2010, our net loss of $2.1 million included non-cash DD&A expense of $112,000, non-cash amortization of our discount on the Amended Debentures of $672,000 and a non-cash gain on reorganization of approximately $1.1 million. Cash used in operating activities was $1.9 million during the nine months ended September 30, 2010 compared to $2.5 million for the same period of 2009.

Cash Flow from Investing Activities

Cash provided by investing activities was $1.0 million during the nine months ended September 30, 2010, representing a $1.3 million increase compared to cash used in investing activities of $309,000 for the nine months ended September 30, 2009. This increase was due to an increase in drilling operations under the Farmout Agreement.

Cash Flow from Financing Activities

Cash of $250,000 was provided by financing activities during the nine months ended September 30, 2010, compared to approximately $4.1 million for the nine months ended September 30, 2009. During the first three quarters of 2009, we raised $1.5 million from the issuance of additional debentures, and the Company sold 1,666,667 shares of common stock to WCOF for total proceeds of $3.5 million.

Off Balance-Sheet Arrangements

We do not have any off-balance sheet financing arrangements as of September 30, 2010.

Critical Accounting Policies and Estimates

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2009 and to the footnote disclosures included in Part I, Item 1 of this Quarterly Report.

ITEM 4T. CONTROLS AND PROCEDURES.

We maintain a system of disclosure controls and procedures that is designed to ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and to ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Acting Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

As of September 30, 2010, we carried out an evaluation, under the supervision and with the participation of our management, including the Chief Executive Officer and the Acting Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, the Chief Executive Officer and the Acting Chief Financial Officer concluded that our disclosure controls and procedures are effective as of the end of the period covered by this Quarterly Report on Form 10-Q.

There was no change in our internal control over financial reporting that occurred during the quarter ended September 30, 2010 that has materially affected, or is reasonably likely to materially affect, the effectiveness of our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

We are not currently party to any material pending litigation.

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ITEM 1A. RISK FACTORS.

There have been no material changes to the risk factors contained in our Annual Report on Form 10-K for the year ended December 31, 2009.

ITEM 5. OTHER INFORMATION.

ITEM 6. EXHIBITS.

Exhibit Number		Description
2.1		Modified Second Amended Joint Plan of Reorganization Filed by PRB Energy, Inc. and PRB Oil & Gas, Inc., dated December 3, 2008 (incorporated herein by reference to Exhibit 99.1 to our Current Report on Form 8-K filed on January 21, 2009)

3.1		Amended and Restated Articles of Incorporation of Black Raven Energy, Inc. (incorporated herein by reference to Exhibit 3.1 to our Current Report on Form 8-K filed on February 6, 2009)

3.2		Amended and Restated Bylaws of Black Raven Energy, Inc. (incorporated herein by reference to Exhibit 3.2 to our Current Report on Form 8-K filed on February 6, 2009)

4.1		Amended and Restated Senior Secured Debenture (incorporated herein by reference to Exhibit 4.1 to our Current Report on Form 8-K filed on February 6, 2009)

10.1┼		Farmout Agreement, dated July 23, 2010, between Black Raven Energy, Inc. and Atlas Resources, LLC.

10.2┼		Third Amendment to Amended and Restated Senior Secured Debenture, dated July 23, 2010, between Black Raven Energy, Inc. and West Coast Opportunity Fund, LLC.

10.3┼		Fourth Amendment to Amended and Restated Senior Secured Debenture, dated October 12, 2010, between Black Raven Energy, Inc. and West Coat Opportunity Fund, LLC.

31.1┼		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act

31.2┼		Certification of the Acting Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934 as adopted pursuant to Section 302 of the Sarbanes-Oxley Act.

32.1┼		Certification of the Chief Executive Officer and Acting Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act.

┼ Filed herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	Black Raven Energy, Inc.

Date: November 18, 2010	/s/ Thomas E. Riley
	Thomas E. Riley Chief Executive Officer

Date: November 18, 2010	/s/ Patrick A. Quinn
	Patrick A. Quinn Acting Chief Financial Officer

Black Raven Energy, Inc. 10-Q