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 March 31, 2011

Or

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.)

1331 Seventeenth Street, Suite 350
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 March 31, 2011 was 16,776,874.

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TABLE OF CONTENTS

PART I — Financial Information		1
Item 1.	Financial Statements (unaudited)	1
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	12
Item 4.	Controls and Procedures	15
PART II — Other Information		15
Item 1.	Legal Proceedings	15
Item 1A.	Risk Factors	15
Item 6.	Exhibits	16
	Signatures	16

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

Black Raven Energy, Inc.

Condensed Consolidated Balance Sheets

(Unaudited)

(In thousands, except share and per share amounts)

	March 31, 2011			December 31, 2010
Assets
Current assets:
Cash and cash equivalents	$	1,386		$	948
Restricted cash (Note 3)	4,188			5,637
Accounts receivable, net	252			282
Inventory	53			53
Prepaid expenses	118			260
Total current assets	5,997			7,180
Oil and gas properties accounted for under the successful efforts method of accounting:
Proved properties	5,131			5,113
Unproved leaseholds	2,497			3,375
Wells-in-progress	40			48
Total oil and gas properties	7,668			8,536
Less: Accumulated depreciation, depletion and amortization	(1,280		)	(1,265		)
Net oil and gas properties	6,388			7,271
Gathering and other property and equipment	2,967			2,962
Less: Accumulated depreciation and amortization	(997		)	(974		)
Net gathering and other property and equipment	1,970			1,988
Other non-current assets:
Other	154			152
Total other non-current assets	154			152
TOTAL ASSETS	$	14,509		$	16,591

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

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Black Raven Energy, Inc.

Condensed Consolidated Balance Sheets (Continued)

(Unaudited)

(In thousands, except share and per share amounts)

	March 31, 2011			December 31, 2010
Liabilities and Stockholders’ Deficit
Current liabilities:
Accounts payable	$	1,130		$	1,234
Accrued expenses and other current liabilities	649			656
Advances from Atlas (Note 3)	3,492			4,824
Total current liabilities	5,271			6,714
Senior secured debentures, net of discount	18,848			18,848
Asset retirement obligation	246			241
Total liabilities	24,365			25,803
Commitments and Contingencies (Note 8)
Stockholders’ deficit
Common stock, par value $.001; 150,000,000 authorized; 16,776,874 and 16,660,965 issued and outstanding, respectively	17			17
Additional paid-in-capital	30,045			29,744
Accumulated deficit	(39,918		)	(38,973		)
Total stockholders’ deficit	(9,856		)	(9,212		)
TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT	$	14,509		$	16,591

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

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Black Raven Energy, Inc.

Condensed Consolidated Statements of Operations

(Unaudited)

(In thousands, except share and per share amounts)

	Three Months Ended
	March 31,
	2011			2010

Operating revenue and other income:
Natural gas sales	$	124		$	143
Gain on sale of oil and gas properties (Note 3)	109			—
Total operating revenue and other income	233			143
Operating expenses:
Natural gas production expense	113			160
Depreciation, depletion, amortization and accretion	43			35
General and administrative	564			643
Total operating expenses	720			838
Operating loss	(487		)	(695		)
Other income (expense):
Interest and other income	7			1
Gain (loss) on disposal of assets	—			(6		)
Interest expense	(465		)	(464		)
Total other expense	(458		)	(469		)
Loss before reorganization items and income taxes	(945		)	(1,164		)
Reorganization items:
Gain on reorganization	—			1,069
Professional fees	—			(4		)
Total reorganization items	—			1,065
Net loss before income taxes	(945		)	(99		)
Income tax provision/benefit	—			—
Net loss	$	(945	)	$	(99	)
Net loss per common share—basic and diluted	$	(0.06	)	$	(0.01	)
Basic and diluted weighted average shares outstanding	16,777,966			16,659,315

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

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Black Raven Energy, Inc.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(In thousands)

	Three Months Ended
	March 31,
	2011			2010
Cash flows from operating activities
Net loss	$	(945	)	$	(99	)
Adjustments to reconcile net loss to net cash used in operating activities:
Gain on sale of oil and gas properties	(109		)	—
Depreciation, depletion, amortization and accretion	43			35
Amortization of debt issuance costs	—			18
Amortization of discount on debentures	—			332
Share-based compensation expense	63			55
Non-cash interest expense	237			—
Gain on reorganization	—			(1,069		)
Loss on sale of assets	—			6
Changes in assets and liabilities:
Accounts receivable	30			9
Prepaid expenses	142			(31		)
Other non-current assets	(1		)	(10		)
Restricted cash (Note 3)	1,449			—
Advances from Atlas (Note 3)	(1,332		)	—
Accounts payable	(98		)	(15		)
Accrued expenses and other current liabilities	(8		)	15
Net cash used in operating activities	(529		)	(754		)
Cash flows from investing activities
Capital expenditures	(53		)	(23		)
Proceeds from Farmout Agreement (Note 3)	1,020			—
Net cash provided by (used in) investing activities	967			(23		)
Net increase (decrease) in cash	438			(777		)
Cash—beginning of period	948			1,064
Cash and cash equivalents—end of period	$	1,386		$	287
Supplemental disclosure of cash flow activity
Cash paid for interest	230			117
Supplemental schedule of non-cash investing and financing activities
Accrued capital expenditures	—			2

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

March 31, 2011

(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”), 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, the Company 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 the Company’s and PRB Oil and Gas, Inc.’s (“PRB Oil”), a wholly-owned subsidiary, Modified Second Amended Joint Plan of Reorganization (the “Plan”). The effective date of the Plan was February 2, 2009 (the “Effective Date”). After the Effective Date, PRB Oil was merged into the Company.

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 had no significant assets or liabilities as of March 31, 2011 and December 31, 2010 and no significant operations for the quarters ended March 31, 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 $0.9 million for the three months ended March 31, 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 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. 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 and to meet the Company’s working capital requirements. There can be no assurances that the cash flow generated from the Farmout Agreement will be sufficient to execute the Company’s business plan. The Company will also 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 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 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.

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In connection with the preparation of the condensed consolidated financial statements, the Company evaluated subsequent events after the balance sheet date of March 31, 2011, through the filing date of this report.

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 - The Company considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Company continually monitors our positions with, and the credit quality of, the financial institutions with which we invest.

Restricted Cash - Restricted cash includes cash received from Atlas restricted for drilling activities in connection with oil and gas properties subject to the Farmout Agreement. See Note 3 for further discussion of the Farmout Agreement.

Accounts Receivable - Trade accounts receivable are recorded at the invoiced amount. The Company assesses credit risk and allowance for doubtful accounts on a customer specific basis. The Company had an allowance for doubtful accounts of $2,000 at March 31, 2011 and December 31, 2010.

The Company grants credit in the normal course of business to customers in the United States. The Company periodically performs credit analysis and monitors the financial condition of its customers to reduce credit risk. Management periodically reviews accounts receivable aging reports to assess credit risks, and if appropriate, also reviews updated credit information to further assess such risk. In the event that management determines the customers’ accounts receivable collectability as less than probable, management reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount not collectible. Allowances for uncollectible accounts receivable are based on information available and historical experience.

Inventory - Inventory is recorded at cost. The Company periodically reviews the carrying cost of its inventories as compared to current market value for those inventories and adjusts its carrying value to the lower of cost or market. Inventory at March 31, 2011 and December 31, 2010 consisted primarily of tubing, and totaled $53,000.

Income Taxes - The Company recognizes 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. The Company has recognized, before a valuation allowance, a net deferred tax asset attributable to the net operating losses as of March 31, 2011 and December 31, 2010. Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“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, the Company has recorded a full valuation allowance against its net deferred tax assets.

Revenue Recognition - Revenue is 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 as 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. Revenue from the production of gas properties in which we have an interest with other producers is recognized on the basis of our 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.

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,

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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 condensed 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 if 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. Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are 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, amortization and accretion (“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, then 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 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 amount of $18,450,000. We recorded a $1.4 million discount on the Amended Debenture upon issuance. The discount on the Amended Debenture was amortized using the retrospective interest method and was fully amortized during 2010.

Net Earnings (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 March 31, 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 periods ended March 31, 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:

	For the three months ended
	March 31,
	2011	2010
Warrants	1,494,298	1,494,298
Options	1,647,500	1,432,500
Total potentially dilutive shares excluded	3,141,798	2,926,798

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Subsequent to March 31, 2011, 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 condensed consolidated financial statements. For the three months ended March 31, 2011 and 2010, comprehensive loss was 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 March 31, 2011, the Company is not involved in any off-balance sheet arrangements.

Fair Value of Financial Instruments - Our financial instruments, including cash and cash equivalents, restricted cash, accounts receivable, accounts payable and secured debentures, are carried at cost. At March 31, 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 March 31, 2011.

Concentration of Credit Risk - Revenues from customers that represented 10% or more of our gas sales for the three months ended March 31, 2011 and 2010 were as follows:

	Three Months Ended March 31,
Customer	2011		2010
	(% of total revenue)
A	66	%	66	%
B	22	%	34	%
C	12	%	—

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

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 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 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.

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.

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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 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, 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 March 31, 2011, drilling of the Initial Wells had been completed, and Atlas had funded and drilled an additional 40 wells pursuant to the initial Work Plan. The accounts payable balances at March 31, 2011 and December 31, 2010 contain drilling costs related to the Farmout Agreement of $696,000 and $813,000, respectively.

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 March 31, 2011, the Company had received $2,760,000 of well site fees for 46 wells drilled through March 31, 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 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 March 31, 2011, Atlas had funded and drilled 46 wells, and the Company had paid an advisory fee of $460,000.

Restricted cash includes cash received from Atlas restricted for drilling activities in connection with oil and gas properties subject to the Farmout Agreement.

Note 4 —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. 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.

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

	For the
	Three Months Ended
	March 31,
	2011		2010
	(in thousands)
Asset retirement obligations, beginning of period	$	241	$	219
Sale of assets	—		—
Accretion expense	5		5
Revision to estimated cash flows	—		—
Asset retirement obligations, end of period	$	246	$	224

Note 5—Borrowings

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

	March 31,		December 31,
	2011		2010
	(in thousands)
Amended senior secured debentures	$	18,848	$	18,848
Total borrowings	18,848		18,848
Less current portion	—		—
Total borrowings, current portion	$	18,848	$	18,848

Amended and Restated Senior Secured Debenture

On February 2, 2009, 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 amount of $18.45 million. The Amended Debenture superseded and amended the senior secured debentures previously issued by PRB Oil to WCOF and DKR Soundshore Oasis Holding Fund Ltd.

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 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.

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Note 6—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 three months ended March 31, 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. The Company’s effective tax rate for the three months ended March 31, 2011 and 2010, before the valuation allowance on deferred tax asset, was 64.88 % and 36.88%, 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 March 31, 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 three months ended March 31, 2011, there was no change to the Company’s liability for uncertain tax positions.

Note 7—Equity Compensation Plan

On June 3, 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 March 31, 2011, there are 4,165,241 shares of common stock authorized for issuance under the Equity Compensation Plan.

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 estimated fair value as of issuance of $59,000, and vest over three years. 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 estimated fair value as of issuance of $61,500. In October 2010, the Company issued 150,000 options to employees of the Company. The options have an exercise price of $2.00 per share, a total estimated fair value as of issuance of $92,250 and vest over five years.

The following table summarizes activity for options:

	For the Quarter Ended			For the Quarter Ended
	March 31, 2011			March 31, 2010
	Number of Options	Weighted Avg. Exercise Price		Number of Options	Weighted Avg. Exercise Price
Outstanding, beginning of period	1,647,500	$	2.00	1,332,500	$	2.00
Cancelled	—	$	—	—	$	—
Granted	—	$	—	100,000	$	2.00
Forfeitures	—	$	—	—	$	—
Exercised	—	$	—	—	$	—
Outstanding, end of period	1,647,500	$	2.00	1,432,500	$	2.00
Awards vested or expected to vest, end of year	1,421,667	$	2.00	1,074,375	$	2.00
Available for future grants, end of period	2,517,741			2,359,166

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The Company recorded equity compensation expense of $63,000 during the first quarter of 2011 and $55,000 during the first quarter of 2010.

Note 8 —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 $28,000 for the period ended March 31, 2011.

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 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, 2010.

Overview

You should read the following discussion in conjunction with the consolidated financial statements and related notes in Item 1 and our Annual Report on Form 10-K for the year ended December 31, 2010.

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 $0.9 million for the three months ended March 31, 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 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. 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 Note 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 and to meet working capital requirements. There can be no assurances that the cash flow generated from the Farmout Agreement will be sufficient to execute the Company’s business plan. The Company will also 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.

As of March 31, 2011, drilling of the Initial Wells had been completed, and Atlas had funded and drilled an additional 40 wells pursuant to the initial Work Plan.

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 of the issued and outstanding shares of our common stock were cancelled, and the Company

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issued 13.5 million shares of new common stock to WCOF, the principal pre-petition secured creditor. The Company also issued 1,419,339 shares of new 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 other claimants related to accounts payable and accrued expenses and other current liabilities.

As of March 31, 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 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. For additional information on the Amended Debenture, see Note 5 to the accompanying condensed consolidated financial statements.

Results of Operations

Three Months Ended March 31, 2011 (unaudited) Compared to the Three Months Ended March 31, 2010 (unaudited)

The financial information with respect to the three months ended March 31, 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 March 31,						Increase/			Percentage
	(In thousands)						Decrease			Change
	2011			2010			2011 vs 2010			2011 vs 2010
Revenue
Natural gas sales	$	124		$	143		$	(19	)	-13.3	%
Gain on sale of oil and gas properties	109			—			109			—
Total revenue	233			143			90			62.9	%
Operating expenses
Natural gas production expense	113			160			(47		)	-29.4	%
DD&A	43			35			8			22.9	%
G&A	564			643			(79		)	-12.3	%
Total expenses	720			838			(118		)	-14.1	%
Operating loss	(487		)	(695		)	208			29.9	%
Interest and other income	7			(5		)	12			-240.0	%
Interest expense	(465		)	(464		)	1			0.2	%
Reorganization items	—			(4		)	(4		)	-100.0	%
Gain on reorganization	—			1,069			(1,069		)	-100.0	%
Net loss	$	(945	)	$	(99	)	$	(846	)	854.5	%

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Natural Gas Sales

Natural gas sales for the first quarter of 2011 decreased $19,000, or 13%, in comparison to 2010 as a result of a decline in natural gas prices, partially offset by an increase in the volume of natural gas sold. The average sales price during the first quarter of 2011 was $.92 per Mcf lower than the average sales price for the first quarter of 2010 ($3.94 for 2011 compared to $4.86 for 2010) causing a revenue decline of $27,000. Sales volumes increased in the first quarter of 2011 by 2,023 Mcf, from 29,317 Mcf for 2010 to 31,340 Mcf for 2011, causing an increase in revenue of $8,000 for the first quarter of 2011 compared to the first quarter of 2010.

Gain on Sale of Oil and Gas Properties

During the first quarter of 2011, the Company recognized a gain of $109,000 on the sale of proved well sites to Atlas as part of the Farmout Agreement.

Natural Gas Production Expense

Natural gas lease operating expenses in the first quarter of 2011 decreased $47,000, or 29.4%, to $113,000 from $160,000 in the first 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 first quarter of 2011 increased $8,000, or 22.9%, to $43,000 from $35,000 in the first quarter of 2010 as a result of the increase in oil and gas production in 2011.

General and Administrative Expense

General and administrative expenses for the first quarter of 2011 decreased by $79,000, or 12.3%, to $564,000 from $643,000 for the first quarter of 2010. This decrease is attributable to the overhead reimbursement received during the first quarter of 2011 as part of the Farmout Agreement.

Gain on Reorganization

PRB Gathering was dismissed from Chapter 11 Bankruptcy on February 17, 2010 and a gain on reorganization of approximately $1.1 million was recognized during the quarter ended March 31, 2010. No similar gain has been recognized in 2011.

Interest Expense

Interest expense for the first quarter of 2011 increased $1,000 or 0.2% to $465,000 from $464,000 for the first quarter of 2010.

Liquidity and Capital Resources

At March 31, 2011, cash and cash equivalents totaled approximately $1.4 million. At March 31, 2011, the Company had working capital of $727,000, compared to working capital of $466,000 at December 31, 2010.

As noted in the risk factors in Item 1A of our 2010 Annual Report on Form 10-K, 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, working capital requirements, planned drilling, potential acquisitions and other capital expenditures. 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. If we fail to secure financing for future development, we may pursue other financial arrangements through debt agreements, joint venture partners, or farmout agreements. We may be unable to raise additional capital in a timely manner, on acceptable terms or at all.

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Cash Flow Used in Operating Activities

During the three months ended March 31, 2011, our net loss of $0.9 million included non-cash DD&A expense of $43,000 and non-cash stock compensation expense of $63,000. Net cash used in operating activities was $529,000 during the three months ended March 31, 2011 compared to $754,000 for the same period of 2010.

Cash Flow Provided by (Used in) Investing Activities

Net cash provided by investing activities was $967,000 during the three months ended March 31, 2011, representing a $990,000 increase compared to cash used in investing activities of $23,000 for the three months ended March 31, 2010. This increase was due to the Farmout Agreement proceeds received during the first quarter of 2011.

Cash Flow from Financing Activities

There was no cash provided by financing activities during the three months ended March 31, 2011or the three months ended March 31, 2010.

Off Balance-Sheet Arrangements

We do not have any off-balance sheet financing arrangements as of March 31, 2011.

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, 2010 and to the footnote disclosures included in Part I, Item 1 of this Quarterly Report.

ITEM 4. 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 March 31, 2011, 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 were effective for the purposes discussed above 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 three months ended March 31, 2011 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.

As of the date of filing of this Quarterly Report, we are not currently party to any material pending litigation.

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, 2010.

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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)

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

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: May 16, 2011	/s/ Thomas E. Riley
	Thomas E. Riley Chief Executive Officer

Date: May 16, 2011	/s/ Patrick A. Quinn
	Patrick A. Quinn Acting Chief Financial Officer

Black Raven Energy, Inc. 10-Q