10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2012

or

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

For the transition period from                     to                     

Commission File Number:

Bonanza Creek Energy, Inc.

(Exact name of registrant as specified in its charter)

Delaware	61-1630631
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
410 17th Street, Suite 1400
Denver, Colorado	80202
(Address of principal executive offices)	(Zip Code)

(720) 440-6100

(Registrant’s telephone number, including area code)

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.  x Yes  o No

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).  x Yes  o No

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 x	Smaller reporting company o
(Do not check if a smaller reporting company)

SEC 1296 (01-12) Potential persons who are to respond to the collection of information contained in this form are not required to respond unless the form displays a currently valid OMB control number.

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. 40,057,248 shares of common stock were outstanding as of September 30, 2012.

PART I - FINANCIAL INFORMATION

Item 1.Financial Statements.

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(unaudited)

	September 30, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4,845,583		$	2,089,674
Accounts receivable:
Oil and gas sales	29,520,522			17,850,719
Other	12,079,986			5,696,825
Prepaid expenses and other	1,515,475			1,868,016
Inventory of oilfield equipment	2,014,418			3,324,368
Derivative asset	2,714,219			1,297,403
Total current assets	52,690,203			32,127,005
OIL AND GAS PROPERTIES—using the successful efforts method of accounting:
Proved properties	718,962,011			547,878,188
Unproved properties	72,928,364			15,848,703
Wells in progress	69,819,751			23,783,142
	861,710,126			587,510,033
Less: accumulated depreciation, depletion and amortization	(66,199,440		)	(26,759,043		)
	795,510,686			560,750,990
NATURAL GAS PLANT	67,648,720			56,910,232
Less: accumulated depreciation	(2,820,328		)	(1,286,129		)
	64,828,392			55,624,103
PROPERTY AND EQUIPMENT	4,186,352			1,983,037
Less: accumulated depreciation	(611,272		)	(128,731		)
	3,575,080			1,854,306
Oil and gas properties held for sale less accumulated depreciation, depletion, and amortization	5,038,282			9,895,508
LONG-TERM DERIVATIVE ASSET	550,777			678,474
OTHER ASSETS, net	3,344,385			3,418,626
TOTAL ASSETS	$	925,537,805		$	664,349,012
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	62,993,900		$	27,068,326
Oil and gas revenue distribution payable	9,733,852			6,185,983
Contractual obligation for land acquisition	11,999,877			—
Derivative liability	5,339,006			5,276,633
Total current liabilities	90,066,635			38,530,942
LONG-TERM LIABILITIES:
Bank revolving credit	122,300,000			6,600,000
Contractual obligation for land acquisition	33,081,306			—
Ad valorem taxes	7,547,363			3,014,023
Derivative liability	820,565			2,579,175
Deferred income taxes, net	100,160,507			79,603,633
Asset retirement obligations	7,196,824			6,039,723
TOTAL LIABILITIES	361,173,200			136,367,496
COMMITMENTS AND CONTINGENCIES (Notes 7 and 8)
STOCKHOLDERS’ EQUITY:
Preferred stock, $.001 par value, 25,000,000 shares authorized, 0 outstanding	—			—
Common stock, $.001 par value, 225,000,000 shares authorized, 40,057,248 and 39,477,584 issued and outstanding, respectively	40,057			39,478
Additional paid-in capital	518,321,950			515,412,583
Retained earnings	46,002,598			12,529,455
Total stockholders’ equity	564,364,605			527,981,516
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	925,537,805		$	664,349,012

See accompanying notes to these consolidated financial statements.

2

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
NET REVENUES
Oil and gas sales	$	58,327,823		$	25,915,330		$	157,613,348		$	70,608,993
OPERATING EXPENSES:
Lease operating	8,444,403			4,686,328			22,506,131			12,040,775
Severance and ad valorem taxes	3,021,860			1,342,646			9,387,094			3,778,946
Exploration	6,359,222			18,608			9,563,876			566,210
Depreciation, depletion and amortization	17,715,763			6,329,995			41,751,296			18,472,491
Impairment of proved properties	268,500			623,039			268,500			623,039
General and administrative (including $1,445,910, $132,720, $2,912,248, and $132,720, respectively, of stock compensation)	9,335,266			4,179,301			22,410,369			9,115,956
Total operating expenses	45,145,014			17,179,917			105,887,266			44,597,417
INCOME FROM OPERATIONS	13,182,809			8,735,413			51,726,082			26,011,576
OTHER INCOME (EXPENSE):
Other loss	(90,640		)	(3,526		)	(82,930		)	(100,805		)
Interest expense	(1,125,634		)	(1,121,907		)	(2,341,843		)	(2,686,684		)
Unrealized (loss) gain in fair value of commodity derivatives	(9,007,034		)	8,268,367			2,985,356			7,095,912
Loss in fair value of commodity derivatives	(92,812		)	(519,287		)	(1,173,619		)	(2,353,187		)
Total other income (expense)	(10,316,120		)	6,623,647			(613,036		)	1,955,236
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES	2,866,689			15,359,060			51,113,046			27,966,812
Income tax expense	(1,222,450		)	(8,527,646		)	(19,797,360		)	(13,176,124		)
INCOME FROM CONTINUING OPERATIONS	$	1,644,239		$	6,831,414		31,315,686			$	14,790,688
DISCONTINUED OPERATIONS (Note 3)
Loss from operations associated with oil and gas properties held for sale	(1,410,595		)	(3,754,649		)	(791,394		)	(3,635,226		)
Gain on sale of oil and gas properties	4,279,998			—			4,279,998			—
Income tax (expense) benefit	(1,092,755		)	1,756,587			(1,331,147		)	1,712,555
Income (loss) associated with oil and gas properties held for sale	1,776,648			(1,998,062		)	2,157,457			(1,922,671		)
NET INCOME	$	3,420,887		$	4,833,352		$	33,473,143		$	12,868,017
BASIC AND DILUTED INCOME PER SHARE
Income from continuing operations	$	0.04		$	0.23		$	0.79		$	0.51
Income (loss) from discontinued operations	$	0.05		$	(0.06	)	$	0.06		$	(0.07	)
Net income per common share	$	0.09		$	0.17		$	0.85		$	0.44
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—BASIC AND DILUTED	39,477,101			29,122,521			39,476,133			29,122,521

See accompanying notes to these consolidated financial statements.

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Nine Months Ended September 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	33,473,143		$	12,868,017
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	43,900,774			21,083,067
Impairment of oil and gas properties	1,916,690			4,067,023
Deferred income taxes	20,556,874			11,463,569
Non-cash stock compensation	2,912,248			—
Exploration	7,378,612			—
Amortization of deferred financing costs	501,315			702,490
Valuation (increase) decrease in commodity derivatives	(2,985,356		)	(7,095,912		)
Gain on sale of oil and gas properties	(4,279,998		)	—
Other	70,563			92,352
(Increase) decrease in operating assets:
Accounts receivable	(18,152,964		)	(6,060,781		)
Prepaid expenses and other assets	352,541			(182,034		)
(Decrease) increase in operating liabilities:
Accounts payable and accrued liabilities	7,149,501			534,255
Settlement of asset retirement obligations	(146,125		)	(138,614		)
Net cash provided by operating activities	92,647,818			37,333,432
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of oil and gas properties	5,212,000			—
Acquisition of oil and gas properties	(12,809,268		)	(1,383,009		)
Exploration and development of oil and gas properties	(183,357,438		)	(91,906,848		)
Natural gas plant capital expenditures	(12,009,040		)	(18,063,482		)
Proceeds from note receivable	—			986,906
Decrease in restricted cash	252,580			—
Additions to property and equipment—non oil and gas	(2,203,315		)	(485,176		)
Net cash used in investing activities	(204,914,481		)	(110,851,609		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in bank revolving credit	115,700,000			145,900,000
Payment on bank revolving credit	—			(69,200,000		)
Deferred financing costs	(677,428		)	(3,029,254		)
Net cash provided by financing activities	115,022,572			73,670,746
NET INCREASE IN CASH AND CASH EQUIVALENTS	2,755,909			152,569
CASH AND CASH EQUIVALENTS:
Beginning of period	2,089,674			—
End of period	$	4,845,583		$	152,569
SUPPLEMENTAL CASH FLOW DISCLOSURE:
Cash paid for interest	$	1,224,331		$	1,876,866
Cash paid for income taxes	$	185,765		—
Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition	$	36,857,282		$	14,135,675
Contractual obligation for land acquisition	$	45,081,183		$	—

See accompanying notes to these consolidated financial statements.

4

Bonanza Creek Energy, Inc.

Notes to the Consolidated Financial Statements as of September 30, 2012 (unaudited)

1. ORGANIZATION AND BUSINESS:

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

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

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

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

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

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

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

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

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

The Company is engaged primarily in acquiring, developing, exploiting and producing oil and gas properties. As of September 30, 2012, the Company’s assets and operations are concentrated primarily in the Wattenberg field and North Park Basin in the Rocky Mountains and in southern Arkansas.

2. BASIS OF PRESENTATION:

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The quarterly financial statements included herein do not necessarily include all of the disclosures as may be required under generally accepted accounting principles. The readers of these quarterly financial statements should also read the audited consolidated financial statements and related notes of BCEI that were included in BCEI’s Annual Report on Form 10-K filed with the SEC on March 22, 2012. These consolidated financial statements include all of the adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and results of operations. All such adjustments are of a normal recurring nature only. The results of operations for the quarterly periods are not necessarily indicative of the results to be expected for the full fiscal year.

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

5

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

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

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

3. ACQUISTIONS AND DIVESTITURES:

On July 31, 2012, the Company acquired leases to approximately 5,600 net acres in the Wattenberg field from the State of Colorado, State Board of Land Commissioners. The Company paid approximately $12 million at closing and will pay approximately $12 million on July 31st of each of the next four years. These future payments were discounted based on our effective borrowing rate to arrive at the purchase price of $57,000,000. These future payments are secured by a letter of credit and interest will be imputed on the future payments.

During June of 2012, the Company began marketing, with an intent to sell, all of its oil and gas properties in California. Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted and a measurement for impairment is performed to expense any excess of carrying value over fair value less costs to sell. The Company determined that its intent to sell these properties qualifies for discontinued operations and, on August 31, 2012, the Company sold a portion of the properties for approximately $5.1 million and recorded a gain on the sale of oil and gas properties in the amount of $4.3 million related to this transaction. The carrying amounts of the major classes of assets and liabilities related to the operation of the remaining properties that are held for sale as of September 30, 2012 and December 31, 2011 are presented below:

	As of September 30, 2012			As of December 31, 2011
PROPERTY AND EQUIPMENT:
Oil and gas properties, successful efforts method:
Proved properties	$	7,799,582		$	13,060,597
Unproved properties	32,013			32,013
Wells in progress	30,629			167,198
Total property and equipment	7,862,224			13,259,808
Less accumulated depletion and depreciation	(2,823,942		)	(3,364,300		)
Net property and equipment	$	5,038,282		$	9,895,508
ASSET RETIREMENT OBLIGATIONS	$	769,700		$	975,562

Total revenues and costs and expenses, and the income associated with the operation of the oil and gas properties held for sale for the three and nine month periods ended September 30, 2012 and 2011 are presented below.

	Three Months Ended September 30			Three Months Ended September 30			Nine MonthsEnded September 30			Nine Months Ended September 30
	2012			2011			2012			2011
NET REVENUES:
Oil and gas sales	$	1,274,906		$	1,458,198		$	5,000,665		$	4,927,493
OPERATING EXPENSES:
Lease operating	451,795			795,428			1,853,085			2,419,715
Severance and ad valorem taxes	8,809			(1,000		)	124,298			81,449
Exploration	6,219			400			17,008			6,995
Depreciation, depletion and amortization	570,488			974,035			2,149,478			2,610,576
Impairment of proved properties	1,648,190			3,443,984			1,648,190			3,443,984
TOTAL COSTS AND EXPENSES	2,685,501			5,212,847			5,792,059			8,562,719
LOSS FROM OPERATIONS ASSOCIATED WITH OIL AND GAS PROPERTIES HELD FOR SALE	$	(1,410,595	)	$	(3,754,649	)	$	(791,394	)	$	(3,635,226	)

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4. RECENT ACCOUNTING PRONOUNCEMENTS:

In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). The objective of ASU 2011-11 is to require an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. ASU 2011-11 is effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively. The adoption of this standard is not expected to have an impact on the Company’s consolidated financial statements.

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

5. ACCOUNTS PAYABLE AND ACCRUED EXPENSES:

Accounts payable and accrued expenses contain the following:

	2012		2011
Drilling and completion costs	$	51,010,731	$	14,153,449
Accounts payable trade	267,213		4,976,979
Ad valorem taxes	190,627		1,781,021
Accrued general and administrative cost	5,039,156		1,713,708
Accrued initial public offering expenses	—		1,258,791
Lease operating expense	2,510,000		2,128,470
Accrued reclamation cost	400,000		400,000
Accrued interest	634,162		17,965
Accrued oil and gas hedging	314,537		353,897
Production taxes and other	2,627,474		284,046
	$	62,993,900	$	27,068,326

6. SENIOR SECURED REVOLVING CREDIT FACILITY:

Senior Secured Revolving Credit Facility—On May 8, 2012, the Company amended its senior secured revolving Credit Agreement, (the “Revolver”) dated March 29, 2011, with a syndication of banks, including KeyBank National Association as the administrative agent and issuing lender, which provides for borrowings of up to $600 million. The Revolver provides for interest rates plus an applicable margin to be determined based on the London Interbank Offered Rate (LIBOR) or a bank base rate (“Base Rate”), at the Company’s election. LIBOR borrowings bear interest at LIBOR plus 1.75% to 2.75% depending on the utilization level, and the Base Rate borrowings bear interest at the “Bank Prime Rate,” as defined plus .75% to 1.75%.

The Revolver had a $245 million borrowing base as of September 30, 2012 and is subject to semi-annual re-determinations in April and October of each year. The letter of credit that was issued to the Colorado State Board of Land Commissioners reduced the borrowing base by approximately $48 million.  The Revolver provides for commitment fees ranging from 0.375% to 0.50%, depending on utilization, and restricts, among other items, the payment of dividends, certain additional indebtedness, sale of assets,

7

loans, and certain investments and mergers. The Revolver also contains certain financial covenants, which require the maintenance of a minimum current ratio and a minimum debt coverage ratio, as defined. The Company was in compliance with these covenants as of September 30, 2012. The Revolver is collateralized by substantially all the Company’s assets and matures on September 15, 2016.

7. COMMITMENTS AND CONTINGENT LIABILITIES:

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

	Office Leases		Wattenberg FieldLease Acquisition		Line of Credit		Total
2012	$	297,265	$	—	—		$	297,265
2013	1,098,709		11,999,987		—		13,098,696
2014	1,085,740		11,999,987		—		13,085,727
2015	1,111,256		11,999,987		—		13,111,243
2016 and thereafter	2,235,743		11,999,987		122,300,000		136,535,730
	$	5,828,713	$	47,999,948	$	122,300,000	$	176,128,661

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

Legal Proceedings—From time to time, the Company is subject to legal proceedings and claims that arise in the ordinary course of business. Like other gas and oil producers and marketers, the Company’s operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. As of the date of this filing, there are no material pending or overtly threatened legal actions against the Company of which it is aware.

In June 2011, Frank H. Bennett, a co-manager of BCOC, BCEC’s predecessor, and former chairman of BCEC, made a demand against Michael R. Starzer, our President and Chief Executive Officer, focusing on Mr. Starzer’s handling of the operation, accounting and finances of BCOC and BCEC primarily during the 2005-2006 time period. Mr. Bennett’s demands do not allege any wrongdoing by or claims against Bonanza Creek Energy, Inc. This matter was sent to arbitration in July 2011.

In July 2011, the Company’s board of directors formed a Special Litigation Committee comprised of three non-executive directors to conduct an investigation of the allegations. The Special Litigation Committee retained outside independent advisors and conducted an in-depth investigation. The Special Litigation Committee concluded that neither it nor its legal or financial advisors had found any evidence to support any of Mr. Bennett’s allegations. The Company’s Board of Directors concluded that the allegations against Mr. Starzer are unsubstantiated and lack merit. However, there can be no assurance as to the ultimate outcome of the arbitration proceedings. An arbitration hearing commenced in July 2012 and it is not clear when a final decision will be rendered regarding the allegations or any potential recovery of legal fees. Mr. Starzer plans to continue to vigorously defend against Mr. Bennett’s claims. During the period from January 1, 2012 through September 30, 2012, the Company incurred approximately $2.5 million for the advancement of legal fees related to Mr. Bennett’s claims.

8. FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION:

The Company follows FASB ASC 820, Fair Value Measurements and Disclosures, which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

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Level 1:Quoted prices are available in active markets for identical assets or liabilities;

Level 2:Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; or

Level 3:Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

Financial assets and liabilities to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2012 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3
Commodity derivative assets	$	—	$	825,074	$	2,439,922
Commodity derivative liabilities	$	—	$	6,159,571	$	—

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2011 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3
Commodity derivative assets	$	—	$	1,094,055	$	881,822
Commodity derivative liabilities	$	—	$	6,740,213	$	1,115,595

Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.  All valuations were compared against counterparty statements to verify the reasonableness of the estimate.  The Company’s commodity swaps are validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and are designated as Level 2 within the valuation hierarchy. The Company’s collars, which are designated as Level 3 within the valuation hierarchy, are not validated by observable transactions with respect to volatility. The counterparties in all of the commodity derivative financial instruments are lenders on the Company’s senior secured revolving credit facility.

The following table reflects the activity for the commodity derivatives measured at fair value using Level 3 inputs during the period from January 1, 2012 through September 30, 2012:

	Derivative Asset			Derivative Liability
Beginning net asset (liability) balance	$	881,822		$	(1,115,595	)
Net increase in fair value	(654,780		)	4,978,506
Net realized (gain) on settlement	(231,511		)	(233,412		)
New derivatives	411,178			(1,596,286		)
Transfers in (out) of Level 3	—			—
Ending net asset (liability) balance	$	406,709		$	2,033,213

As of September 30, 2012, the Company’s derivative commodity contracts:

Contract Term	Notional Volume	Average Floor		Average Ceiling		Average Fixed Price
October 1 - December 31, 2012	77,956 Bbl./Month	$	90.00	$	106.05	—
January 1 - December 31, 2013	44,218 Bbl./Month	$	91.61	$	106.46	—
October 1 - December 31, 2012	49,400 Bbl./Month	—		—		$	88.78
January 1 - December 31, 2013	76,285 Bbl./Month	—		—		$	88.08
October 1 - December 31, 2012	323,103 MMBTU/Month	—		—		$	3.33
January 1 - October 31, 2013	15,481 MMBTU/Month	—		—		$	6.40

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The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of September 30, 2012:

Derivatives	Balance Sheet Location	Fair Value
Asset
Commodity derivatives	Current derivative assets	$	2,714,219
Commodity derivatives	Long-term derivative assets	550,777
Liability
Commodity derivatives	Current derivative liability	(5,339,006		)
Commodity derivatives	Long-term derivative liability	(820,565		)
Total		$	(2,894,575	)

Realized gains and losses on commodity derivatives and the unrealized gains or losses are recorded in other income (expense).

Asset Retirement Obligation—Upon completion of wells and natural gas plants, the Company records an asset retirement obligation at fair value using Level 3 assumptions.

Proved Oil and Gas Properties—Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs exceed the sum of the undiscounted cash flows. The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts selected by the Company’s management. The calculation of the discount rate is a significant management estimate based on the best information available and estimated to be 10 percent for the nine months ended September 30, 2011. Management believes that the discount rate is representative of current market conditions and reflects the following factors: estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on New York Mercantile Exchange (“NYMEX”) strip pricing, adjusted for basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates.

As a result of the impairment discussed in Note 11—Impairment of Proved Properties, the proved oil and gas properties measured at fair value within the accompanying balance sheets as of September 30, 2012 and 2011 were $4.6 million and $6.3 million, respectively.

9. STOCKHOLDERS’ EQUITY:

BCEI Management Incentive Plan—On December 23, 2010, the Company established the Management Incentive Plan (the “Plan” or “MIP”) for the benefit of certain employees, officers and other individuals performing services for the Company. 10,000 shares of Class B common stock were available under the Plan and these shares were converted into 437,787 shares of restricted common stock upon completion of our initial public offering. The conversion rate was determined based on a formula factoring in the rate of return to the common stockholders. The 437,787 shares of common stock that were granted to employees were valued at $17.00 per share on the grant date and vest over a three year period. Non-cash compensation expense of approximately $1,822,000 was recorded during the nine months ended September 30, 2012 and there was approximately $5,372,000 of unrecognized compensation costs related to the unvested restricted common stock granted under the Plan. That cost is expected to be recognized over a period of 2.25 years.

BCEC Management Incentive Plan—As of September 30, 2012, 73,197 shares of BCEI common stock remain held in trust and designated for holders of BCEC’s Class B units. When and if such shares are issued, they will be valued based on the market price of the Company’s common stock on the grant date.

BCEI Long Term Incentive Plan—On June 14, 2012, the Company granted 540,000 shares of restricted common stock under its 2011 Long Term Incentive Plan (the “LTIP”) to officers and certain key employees. For accounting purposes, these shares were valued at $15.38, the closing price of our common stock on the grant date. These shares will vest annually in one-third increments over approximately 2.7 years and will be fully vested in February of 2015. On August 15, 2012, the Company granted an additional 25,000 shares of restricted stock under the LTIP to a newly hired key employee. For accounting purposes, these shares were valued at $19.03, the closing price our common stock on the grant date. These shares will vest annually in one-third increments over 3 years and will be fully vested in August of 2015. On August 3, 2012, the Company granted an aggregate of 16,626 shares of common stock under the LTIP to the four independent members of our Board of Directors in 2011 for their 2011-2012 service.  For accounting purposes, these shares were valued at $18.04, the closing price our common stock on the grant date and vested upon grant and non-cash compensation expense of approximately $300,000 was recorded during the period from April 1, 2011 through June 30, 2012.  On August 3, 2012, the Company granted an aggregate of 16,908 shares of common stock under the LTIP to the four independent members of our Board of Directors in 2012 for their 2012-2013 service.  For accounting purposes, these shares were valued at $18.04, the closing price our common stock on the grant date and will vest immediately prior to the Company’s 2013 Annual Meeting. Non-cash compensation expense of approximately $73,000 was recorded during the quarter ended September 30, 2012.

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10. INCOME TAXES:

The Company uses the asset and liability method of accounting for deferred income taxes.  Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities.  Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time.

The deferred income tax liability for an oil and gas exploration company is dependent on many variables such as estimating the economic lives of depleting oil and gas reserves and commodity prices.  Accordingly, the liability is subject to continual recalculation, revision of the numerous estimates required, and may change significantly in the event of such things as major acquisitions, divestitures, product price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws.

The Company follows the provisions of FASB ASC 740, Accounting for Uncertainty in Income Taxes. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The Company files income tax returns in the U.S. federal jurisdiction and various states. The Company has not taken any uncertain tax positions.

11. IMPAIRMENT OF PROVED PROPERTIES:

The Company recorded $1.6 million of proved property impairments on the Company’s legacy California assets and $0.3 million of proved property impairment in one non-core field in Southern Arkansas for the nine months ended September 30, 2012.  The impairments of the Company’s legacy assets in California were related to anticipated sales proceeds that were lower than the net book value of the properties as of September 30, 2012 and the impairment of the non-core field in Southern Arkansas was related to a the well repair that did not restore the well to its previous production levels.

12.  SUBSEQUENT EVENTS:

On October 11, 2012, the Company sold Liberty Energy, LLC, which owned a 50% non-operated interest in the Sargent field in California, for approximately $3.2 million. During the quarter ended September 30, 2012, an impairment charge in the amount of $460,000 was recorded to write the field down to the sales price and no gain or loss was recorded on this transaction.

On October 30, 2012, the lenders under the Company’s senior secured revolving credit agreement redetermined the Company’s borrowing base resulting in an increase of the borrowing base to $325 million which excludes the value of the oil and gas properties held for sale.

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Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2011 (the “2011 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q (this “Report”).

This Report contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. These forward-looking statements may include projections and estimates concerning our capital expenditures, our liquidity and capital resources, our estimated revenues and losses, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, our business strategy and other statements concerning our operations, economic performance and financial condition. When used in this Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences.

Forward-looking statements may include statements about:

·our ability to replace oil and natural gas reserves;

·declines or volatility in the prices we receive for our oil and natural gas;

·our financial position;

·our cash flow and liquidity;

·general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;

·the recent economic slowdown that has and may continue to adversely affect consumption of oil and natural gas by businesses and consumers;

·our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop our undeveloped acreage positions;

·the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

·uncertainties associated with estimates of proved oil and gas reserves and, in particular, probable and possible resources;

·the possibility that the industry may be subject to future regulatory or legislative actions (including additional taxes and changes in environmental regulation);

·environmental risks;

·drilling and operating risks;

·exploration and development risks;

·competition in the oil and natural gas industry;

·management’s ability to execute our plans to meet our goals;

·our ability to retain key members of our senior management and key technical employees;

·access to adequate gathering systems and pipeline take-away capacity to execute our drilling program;

·our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;

·costs associated with perfecting title for mineral rights in some of our properties;

·continued hostilities in the Middle East and other sustained military campaigns or acts of terrorism or sabotage; and

·other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our businesses, operations or pricing.

All forward-looking statements speak only as of the date of this Report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations below and under “Item 1A. Risk Factors” in our 2011 Annual Report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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Overview

Bonanza Creek Energy, Inc. (“BCEI” or, together with our consolidated subsidiaries, the “Company,” “we,” “us,” or “our”) is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States.  Our assets and operations are concentrated primarily in the Wattenberg Field and North Park Basins in Colorado (Rocky Mountain region) and southern Arkansas (Mid-Continent region).  In addition, we own and operate oil producing assets in the San Joaquin Basin (California region), which are currently classified as discontinued operations.  Our management team has extensive experience acquiring and operating oil and gas properties, which we believe will contribute to the development of our inventory of projects, including those targeting the oily Cotton Valley sands in our Mid-Continent region and the Niobrara oil shale formation in our Rocky Mountain region.  We operate approximately 99.5% and hold an average working interest of approximately 80.7% of our proved reserves, providing us with significant control over the rate of development of our asset base.

As demonstrated by our $165.5 million capital program in 2011 and our amended $298 million capital program in 2012, we are increasingly focused on exploiting our inventory of high-return projects. We also continue to seek acquisitions that will complement our existing core properties.

Our revenue, profitability and future growth rate depend on factors beyond our control, such as economic, political and regulatory developments.  Oil and gas prices historically have been volatile and may fluctuate widely in the future.  We attempt to protect our capital and operational plans by judiciously hedging our sales of oil and natural gas.

Third Quarter 2012 Highlights:

For the third quarter 2012,

·Total production was 865 MBoe (9,403 Boe/d average daily production), a 122% increase over the third quarter 2011 and 9% over the second quarter 2012;

·Total revenue was $58.3 million, a 125% increase over the third quarter 2011 and 13% over the second quarter 2012; and

·Net income was $3.4 million, or $0.09 per diluted share.

Results for Continuing Operations

Three Months Ended September 30, 2012 Compared To Three Months Ended September 30, 2011

Revenues

The following table summarizes our revenues and production data for the periods indicated.

	Three Months Ended September 30,
	2012		2011		Change		Percent Change
	(In thousands, except percentages)
Revenues:
Crude oil sales	$	49,755	$	19,085	$	30,670	161	%
Natural gas sales	4,668		3,598		1,070		30	%
Natural gas liquids sales	3,757		3,150		607		19	%
CO2 sales	148		82		66		80	%
Product revenues	$	58,328	$	25,915	$	32,413	125	%

	Three Months Ended September 30,
	2012	2011	Change	Percent Change
Sales volumes:
Crude oil (MBbls)	567.0	227.3	339.7	149	%
Natural gas (MMcf)	1,388.6	698.3	690.3	99	%
Natural gas liquids (MBbls)	66.6	45.3	21.3	47	%
Crude oil equivalent (MBoe)(1)	865.0	389.0	476.0	122	%

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

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	Three Months Ended September 30,
	2012		2011		Change			Percent Change
Average Sales Prices (before hedging)(1):
Crude oil (per Bbl)	$	87.75	$	83.96	$	3.79		5	%
Natural gas (per Mcf)	3.36		5.15		(1.79		)	(35	)%
Natural gas liquids (per Bbl)	56.41		69.54		(13.13		)	(19	)%
Crude oil equivalent (per Boe)(2)	67.26		66.41		0.85			1	%

	Three Months Ended September 30,
	2012		2011		Change			Percent Change
Average Sales Prices (after hedging)(1):
Crude oil (per Bbl)	$	86.89	$	80.98	$	7.91		10	%
Natural gas (per Mcf)	3.65		5.38		(1.73		)	(32	)%
Natural gas liquids (per Bbl)	56.41		69.54		(13.08		)	(19	)%
Crude oil equivalent (per Boe)(2)	67.15		65.07		2.08			3	%

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

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

Revenues increased by 125%, to $58.3 million for the three months ended September 30, 2012 compared to $25.9 million for the three months ended September 30, 2011. Oil, natural gas and natural gas liquids production increased 149%, 99% and 47%, respectively, during the three months ended September 30, 2012, as compared to the three months ended September 30, 2011. During the period from September 30, 2011 through September 30, 2012, we drilled and completed 108 gross (105.0 net) wells in the Rockies and 45 gross (40.0 net) wells in Southern Arkansas. The increased volumes are a direct result of the $165.5 million expended for drilling and completion during the year ended December 31, 2011, and the $235.5 million expended during the nine months ended September 30, 2012. Oil prices increased from an average of $83.96 in 2011 to a per barrel rate of $87.75 in the comparable three month period that ended September 30, 2012.  Increased oil volumes of 149% accounted for $28.5 million of the total $30.7 million increase in revenues for the Company for the three month period ended September 30, 2012 compared to the same period in 2011.  Natural gas volumes increased by 99% in 2012, but were offset by a sales price decline of 35% from $5.15 per Mcf to $3.36 per Mcf for these three month periods. Natural gas liquids volumes increased by 47% in 2012 with a 19% decrease in prices period over period. Our Wattenberg field natural gas is sold without processing and sells at a premium due to its very high BTU content. Our production of oil, natural gas and natural gas liquids for the three months ended September 30, 2012 was approximately 66%, 27% and 7%, respectively.

Operating Expenses

The following table summarizes our operating expenses for the periods indicated.

	2012		2011		Change			Percent Change
	(In thousands, except percentages)
Expenses:
Lease operating	$	8,444	$	4,686	$	3,758		80	%
Severance and ad valorem taxes	3,022		1,343		1,679			125	%
General and administrative	9,335		4,179		5,156			123	%
Depreciation, depletion and amortization	17,716		6,330		11,386			180	%
Impairment of oil and gas properties	269		623		(354		)	(57	)%
Exploration	6,359		19		6,340			33,368	%
Operating expenses	$	45,145	$	17,180	$	27,965		163	%

	Three Months Ended September 30,
	2012		2011		Change			Percent Change
Selected Costs ($ per Boe):
Lease operating	$	9.76	$	12.05	$	(2.29	)	(19	)%
Severance and ad valorem taxes	3.49		3.45		0.04			1	%
General and administrative	10.79		10.74		0.05			0	%
Depreciation, depletion and amortization	20.48		16.27		4.21			26	%
Impairment of oil and gas properties	0.31		1.60		(1.29		)	(80	)%
Exploration	7.35		0.05		7.30			14,600	%
Operating expenses	$	52.18	$	44.16	$	8.02		18	%

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Lease Operating Expense.  Our lease operating expenses increased $3.8 million, or 80%, to $8.4 million for the three months ended September 30, 2012 from $4.7 million for the three months ended September 30, 2011 and decreased on an equivalent basis from $12.05 per Boe to $9.76 per Boe. The increase in lease operating expense was related to increased production volumes attributable to our drilling program and the operation of an additional gas plant that was constructed during 2011 that came on line during September of 2011. Gas plant operating expense, which is a component of lease operating expense, increased $0.9 million, or 53%, to $2.5 million for the three month period ended September 30, 2012 from $1.6 million for the three month period ended September 30, 2011.  The increase in gas plant operating expense was primarily related to the replacement of a heat exchanger which cost approximately $0.7 million to procure and install. During the three months ended September 30, 2012, well servicing, rental equipment and other expenses were $1.5 million, $0.5 million and $0.7 million higher, respectively, than the three months ended September 30, 2011. The decrease in lease operating expense on an equivalent basis was primarily related to the lower per unit operating costs of the wells drilled during the period from September 30, 2011 through September 30, 2012.

Severance and ad valorem taxes.Our severance and ad valorem taxes increased $1.7 million, or 125%, to $3.0 million for the three months ended September 30, 2012 from $1.3 million for the three months ended September 30, 2011. The increase was primarily related to a 122% increase in production volumes which was further increased by a slight increase in realized prices per Boe during the three months ended September 30, 2012 as compared to the three months ended September 30, 2011. The increase in severance and ad valorem taxes for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011 was related to oil severance taxes and ad valorem taxes that were $1.2 million and $0.3 million, respectively, higher than the comparable period in the previous year.

Exploration costs.  Our exploration expense increased $6.3 million to $6.4 million in the three months ended September 30, 2012 from $19 thousand in the three months ended September 30, 2011. During the three months ended September 30, 2012, a seismic acquisition project in the North Park Basin of Colorado was completed which resulted in charges of approximately $0.3 million, delay rentals were $0.2 million, and two exploratory locations in the North Park basin were also charged to exploration expense. This resulted in a $5.8 million charge to our statement of operations during the three months ended September 30, 2012.

Depletion, depreciation and amortization.Our depletion, depreciation and amortization expense increased $11.4 million, or 180%, to $17.7 million for the three months ended September 30, 2012 from $6.3 million for the three months ended September 30, 2011. Our depreciation, depletion and amortization expense per Boe produced increased $4.21, or 26% to $20.48 for the three months ended September 30, 2012 as compared to $16.27 for the three months ended September 30, 2011. This increase was primarily the result of a 122% increase in production period over period and the inclusion of additional horizontal Niobrara wells in the depletion base.  During the three months ended September 30, 2011 two horizontal Niobrara wells were included in the depletion base as compared to 25 horizontal Niobrara wells that were included in the depletion base during the three months ended September 30, 2012.

Impairment of oil and gas properties.  The Company recorded $0.3 million of proved property impairment in one non-core field in Southern Arkansas for the three months ended September 30, 2012. The Company recorded $0.6 million of proved property impairment in one non-core field in Southern Arkansas for the three months ended September 30, 2011.

General and administrative. Our general and administrative expense increased $5.2 million, or 123%, to $9.3 million for the three months ended September 30, 2012 from $4.2 million for the period ended September 30, 2011. During the three months ended September 30, 2012, wages, benefits and employee placement fees were $2.5 million higher than the three month period ended September 30, 2011 due to our increasing headcount as the result of our accelerated drilling program and the addition of accounting, legal and IT positions that were previously outsourced. During the three months ended September 30, 2012, legal fees were $1.0 million higher and non-cash stock compensation charges for officers and certain employees were $1.4 million higher than the three month period ended September 30, 2011. The majority of the increased general and administrative expense is due to hiring a large number of personnel to support our growth and the regulatory compliance obligations of a newly public company.

Interest expense.  Our interest expense for the three months ended September 30, 2012 was $1.1 million which was commensurate with the three months ended September 30, 2011. Average debt outstanding for the three months ended September 30, 2012 was $121.1 million as compared to $108.1 million for the three months ended September 30, 2011.

Realized loss on settled commodity derivatives.  Realized losses on oil and gas hedging activities decreased by $0.4 million from a loss of $0.5 million for the three months ended September 30, 2011 to a loss of $0.1 million for the three months ended September 30, 2012. The change from a realized loss to a realized gain period over period was primarily related to commodity prices that were 1% higher during the three month period ended September 30, 2012.

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Income tax expense.  Our estimate for federal and state income taxes for the three months ended September 30, 2012 was $1.2 million from continuing operations, as compared to $8.5 million for the three months ended September 30, 2011. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. Our estimate of deferred income taxes for the three month period ended September 30, 2012 was $0.6 million and all income taxes for the three month period ended September 30, 2011 were deferred. Our effective tax rates differ from the U.S. statutory income tax rate primarily due to the effects of state income taxes.

Nine Months Ended September 30, 2012 Compared To Nine Months Ended September 30, 2011

Revenues

The following table summarizes our revenues and production data for the periods indicated.

	Nine Months Ended September 30,
	2012		2011		Change			Percent Change
	(In thousands, except percentages)
Revenues:
Crude oil sales	$	133,880	$	52,253	$	81,627		156	%
Natural gas sales	12,238		9,279		2,959			32	%
Natural gas liquids sales	11,315		8,828		2,487			28	%
CO2 sales	180		249		(68		)	(27	)%
Product revenues	$	157,613	$	70,609	$	87,005		123	%

	Nine Months Ended September 30,
	2012	2011	Change	Percent Change
Sales volumes:
Crude oil (MBbls)	1,462.6	584.7	877.9	150	%
Natural gas (MMcf)	3,740.7	1,821.4	1,919.3	105	%
Natural gas liquids (MBbls)	202.4	128.8	73.6	57	%
Crude oil equivalent (MBoe)(1)	2,288.5	1,017.1	1,271.4	125	%

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

	Nine Months Ended September 30,
	2012		2011		Change			Percent Change
Average Sales Prices (before hedging)(1):
Crude oil (per Bbl)	$	91.53	$	89.37	$	2.16		2	%
Natural gas (per Mcf)	3.27		5.09		(1.82		)	(36	)%
Natural gas liquids (per Bbl)	55.90		68.54		(12.64		)	(18	)%
Crude oil equivalent (per Boe)(2)	68.79		69.18		(0.39		)	(1	)%

	Nine Months Ended September 30,
	2012		2011		Change			Percent Change
Average Sales Prices (after hedging)(1):
Crude oil (per Bbl)	$	90.16	$	84.53	$	5.63		7	%
Natural gas (per Mcf)	3.49		5.36		(1.87		)	(35	)%
Natural gas liquids (per Bbl)	55.90		68.54		(12.64		)	(18	)%
Crude oil equivalent (per Boe)(2)	68.28		66.87		1.41			2	%

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

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

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Revenues increased by 123%, to $157.6 million for the nine months ended September 30, 2012 compared to $70.6 million for the nine months ended September 30, 2011.  Oil, natural gas and natural gas liquids production increased 156%, 32%, and 28%, respectively, during the nine months ended September 30, 2012, as compared to the nine months ended September 30, 2011.  During the period from September 30, 2011 through September 30, 2012, we drilled and completed 108 gross (105.0 net) wells in the Rocky Mountain region and 45 gross (40.0 net) wells in the Mid-Continent region.  The increased volumes are a direct result of the $165.5 million expended for drilling and completion during the year ended December 31, 2011, and the $235.5 million expended during the nine months ended September 30, 2012.  Oil prices increased from an average of $89.37 in 2011 to a per barrel rate of $91.53 in the comparable nine month period that ended September 30, 2012.  The combination of increased oil volumes and prices accounted for $81.6 million of the total $87.0 million increase in revenues for the Company for the nine month period ended September 30, 2012 compared to the same period in 2011.  Natural gas volumes increased by 32% in 2012, but were offset by a sales price decline of 36% from $5.09 per Mcf to $3.27 per Mcf for these nine month periods.  Natural gas liquid volumes increased by 28% in 2012, but were offset by a sales prices decline of 18% from $68.54 per Bbl to $55.90 per Bbl for these nine month periods.  Our Wattenberg field natural gas is sold without processing and sells at a premium due to its very high BTU content.  Our production of oil, natural gas and natural gas liquids for the nine months ended September 30, 2012 was approximately 64%, 27% and 9%, respectively.

Operating Expenses

The following table summarizes our operating expenses for the periods indicated.

	2012		2011		Change			Percent Change
	(In thousands, except percentages)
Expenses:
Lease operating	$	22,506	$	12,041	$	10,465		87	%
Severance and ad valorem taxes	9,387		3,779		5,608			148	%
General and administrative	22,410		9,116		13,294			146	%
Depreciation, depletion and amortization	41,751		18,472		23,279			126	%
Impairment of oil and gas properties	269		623		(354		)	(57	)%
Exploration	9,564		566		8,998			1,590	%
Operating expenses	$	105,887	$	44,597	$	61,290		137	%

	Nine Months Ended September 30,
	2012		2011		Change			Percent Change
Selected Costs ($ per Boe):
Lease operating	$	9.83	$	11.84	$	(2.01	)	(17	)%
Severance and ad valorem taxes	4.10		3.72		0.38			10	%
General and administrative	9.79		8.96		0.83			9	%
Depreciation, depletion and amortization	18.24		18.16		0.08			0	%
Impairment of oil and gas properties	0.12		0.61		(0.49		)	(80	)%
Exploration	4.18		0.56		3.62			646	%
Operating expenses	$	46.26	$	43.85	$	2.41		7	%

Lease Operating Expense.  Our lease operating expenses increased $10.5 million, or 87%, to $22.5 million for the nine months ended September 30, 2012 from $12.0 million for the nine months ended September 30, 2011 and decreased on an equivalent basis from $11.84 per Boe to $9.83 per Boe.  The increase in lease operating expense was related to increased production volumes attributable to our drilling program and the operation of an additional gas plant that was constructed during 2011 that came on line during September of 2011.  Gas plant operating expense, which is a component of lease operating expense, increased $2.3 million, or 54%, to $6.5 million for the nine month period ended September 30, 2012 from $4.2 million for the nine month period ended September 30, 2011.  A portion of the increase in gas plant operating expense was related to the replacement of a heat exchanger which cost approximately $0.7 million to procure and install.  Other increases in gas plant operating expenses period over period were for compression and rental equipment and utilities and electrical which were $1.1 million and $0.4 million, respectively.  During the nine months ended September 30, 2012, well servicing, rental equipment, pumping and gauging and other expenses were $4.4 million, $0.5 million, $0.2 million and $0.8 million higher, respectively, than the nine months ended September 30, 2011.  The decrease in lease operating expense on an equivalent basis was primarily related to accretive drilling and the lower per unit operating costs of the wells drilled during the period from September 30, 2011 through September 30, 2012.

Severance and ad valorem taxes.Our severance and ad valorem taxes increased $5.6 million, or 148%, to $9.4 million for the nine months ended September 30, 2012 from $3.8 million for the nine months ended September 30, 2011.  The increase was primarily related to a 125% increase in production volumes and higher ad valorem tax assessments.  The increase in severance and ad valorem

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taxes on a Boe basis for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011 was related to oil severance taxes and ad valorem taxes that were $3.0 million and $2.4 million, respectively, higher than the comparable period in the previous year.

General and administrative. Our general and administrative expense increased $13.3 million, or 146%, to $22.4 million for the nine months ended September 30, 2012 from $9.1 million for the nine months ended September 30, 2011. During the nine months ended September 30, 2012, wages, benefits and employee placement fees were $7.3 million higher than the nine month period ended September 30, 2011 due to our headcount increasing as the result of our accelerated drilling program and the addition of accounting, legal and IT positions that were previously outsourced. During the nine months ended September 30, 2012, accounting fees were $0.4 million higher due to a one-time payment that was made to our outsource accounting provider to terminate our agreement with them. Also during the nine months ended September 30, 2012, legal fees were $2.0 million higher, franchise taxes were $0.3 million higher and non-cash stock compensation charges for officers and certain employees were $2.9 million higher than the nine month period ended September 30, 2011. The majority of the increased general and administrative expense is due to hiring a large number of personnel to support our growth, advancement of legal fees in the Bennett arbitration matter and the regulatory compliance obligations of a newly public company.

Depletion, depreciation and amortization.Our depletion, depreciation and amortization expense increased $23.3 million, or 126%, to $41.8 million for the nine months ended September 30, 2012 from $18.5 million for the nine months ended September 30, 2011.  Our depreciation, depletion and amortization expense per Boe produced increased $0.08, to $18.24 for the nine months ended September 30, 2012 as compared to $18.16 for the nine months ended September 30, 2011.  This increase was primarily the result of a 125% increase in production period over period.

Impairment of oil and gas properties.  The Company recorded $0.3 million of proved property impairment in one non-core field in the Mid-Continent region for the nine months ended September 30, 2012.  The Company recorded $0.6 million of proved property impairment in one non-core field in the Mid-Continent region for the nine months ended September 30, 2011.

Exploration costs.  Our exploration expense increased $9.0 million, or 1,590%, to $9.6 million in the nine months ended September 30, 2012 from $0.6 million in the nine months ended September 30, 2011.  During the nine months ended September 30, 2012, the following items were charged to exploration expense: a seismic acquisition project in the amount of $1.9 million that was conducted in the North Park Basin of Colorado, three exploratory locations in the North Park basin in the amount of $7.4 million that were written off and the payment of delay rentals in the amount of $0.3 million.  During the nine months ended September 30, 2011, we acquired 7,700 acres of 3-D seismic data on the eastern edge of the Wattenberg field in Weld County, Colorado to help evaluate our Niobrara oil shale acreage.

Interest expense.  Our interest expense decreased $0.4 million, or 12%, to $2.3 million for the nine months ended September 30, 2012 from $2.7 million for the nine months ended September 30, 2011.  The decrease resulted from a decrease in the average debt outstanding for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.  Average debt outstanding for the nine months ended September 30, 2012 was $60.5 million as compared to $81.6 million for the nine months ended September 30, 2011.

Realized loss on settled commodity derivatives.  Realized losses on oil and gas hedging activities decreased by $1.2 million from a loss of $2.4 million for the nine months ended September 30, 2011 to a loss of $1.2 million for the nine months ended September 30, 2012.  The decrease in the realized loss period over period was primarily related to hedging gains in the amount of $0.9 million during the months of June and July as the NYMEX sweet crude oil price averaged $82.41 and $87.93 per barrel, respectively, during the months of June and July of 2012 as compared to our oil hedges which had an average floor of $88.61 per barrel during these months.

Income tax expense.  Our estimate for federal and state income taxes for the nine months ended September 30, 2012 was $19.8 million from continuing operations as compared to $13.2 million for the nine months ended September 30, 2011.  We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation.  Our estimate of current and deferred income taxes for the nine month period ended September 30, 2012 were $0.6 million and $20.5 million, respectively, and all income taxes for the period ended September 30, 2011 were deferred.  Our effective tax rates differ from the U.S. statutory income tax rate primarily due to the effects of state income taxes.

Results for Discontinued Operations

During June of 2012, the Company began marketing, with an intent to sell, all of our oil and gas properties in California.  Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year.  The Company determined that our intent to sell these properties qualifies for discontinued operations accounting and these assets will be presented as discontinued operations in the Company’s statements of operations.

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The operating results before income taxes for our California properties for the three month period ended September 30, 2012 were net revenues, gain on the sale of the Kern River property, operating expenses and gain from discontinued operations of $1.3 million, $4.3 million, $2.7 million and $2.9 million, respectively, as compared to net revenues, operating expenses and loss from discontinued operations of $1.5 million, $5.2 million and ($3.7) million for the three month period ended September 30, 2011.  Operating expenses for the three months ended September 30, 2012 include impairments that were recorded to the Sargent and Greeley properties in the amount of $1.6 million to reduce the net book value of these properties to the expected sales proceeds.  Operating expenses for the three months ended September 30, 2011 include impairments that were recorded to the legacy California properties in the amount of $3.4 million.  Sales volumes for the three month periods ended September 30, 2012 and 2011 were 13.1 MBbls and 15.2 MBbls, respectively.

The operating results before income taxes for our California properties for the nine month period ended September 30, 2012 were net revenues, gain on the sale of the Kern River property, operating expenses and gain from discontinued operations of $5.0 million, $4.3 million, $5.8 million and $3.5 million, respectively, as compared to net revenues, operating expenses and loss from discontinued operations of $4.9 million, $8.6 million and ($3.7) million for the nine month period ended September 30, 2011.  Operating expenses for the nine months ended September 30, 2012 include impairments that were recorded to the Sargent and Greeley properties in the amount of $1.6 million to reduce the net book value of these properties to the expected sales proceeds.  Operating expenses for the nine months ended September 30, 2011 include impairments that were recorded to the legacy California properties in the amount of $3.4 million.  Sales volumes for the nine month periods ended September 30, 2012 and 2011 were 49.7 MBbls and 49.9 MBbls, respectively.

Liquidity and Capital Resources

Our primary source of liquidity to date has been proceeds from our initial public offering, borrowings under our revolving credit facility and cash flows from operations.  Our primary use of capital has been the development and exploitation of our oil and gas properties.  We continually monitor potential capital sources in order to adequately plan for the growth of the Company and our planned capital expenditures and liquidity requirements.  Our future success in building and growing the Company’s reserves and production will be significantly dependent upon management’s ability to access outside sources of capital.

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

On April 6, 2012, the administrative agent under our credit facility was changed to KeyBank, National Association.  On May 8, 2012, we entered into an amendment with the lenders under our credit facility to, among other things, (i) increase our credit facility to $600 million and borrowing base to $245 million, and (ii) make changes in the covenant applicable to hedging to allow greater flexibility for management to implement comprehensive hedging plans to adequately protect the Company’s operations and capital budgets.  As of September 30, 2012, we had $122.3 million outstanding and $122.7 million of borrowing capacity available under our credit facility.

On July 31, 2012, the Company acquired leases in the Wattenberg field from the State of Colorado, State Board of Land Commissioners.  The company paid approximately $12 million at closing and will pay approximately $12 million on July 31st of each of the next four years.  These future payments are secured by a letter of credit which reduced our availability under the borrowing base.

We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas.

We are of the opinion that we have adequate liquidity to manage our capital and business plans for the next 12 months and the foreseeable future.  In addition, we believe that the combination of our cash flow from operating activities, potential access to debt and capital markets and our current liquidity level will allow us the flexibility to modify our future capital expenditure programs and comply with all of our debt covenants, and meet all of our obligations that may arise from our ongoing operations.

The following table summarizes our cash flows and other financial measures for the periods indicated.

	Nine Months Ended September 30,
	2012			2011
	(In thousands)
Net cash provided by operating activities	$	92,648		$	37,333
Net cash provided by (used in) investing activities	(204,914		)	(110,852		)
Net cash provided by financing activities	115,023			73,671
Cash and cash equivalents	4,846			153
Acquisitions of oil and gas properties	12,809			1,383
Exploration and development of oil and gas properties and investment in gas processing facility	195,366			57,407

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Cash flows provided by operating activities

Cash flows derived from operating activities depend on many factors, including the price for oil and gas and our success in exploiting and exploring our oil and gas properties which ultimately leads to the volumes produced.  Costs to produce the oil and gas, our ability to contain such costs, and the severance and ad valorem taxes associated with the ownership and production of oil and gas wells have a significant impact on our profitability and cash flow from our oil and gas properties.

Net cash provided by operating activities was $92.6 million for the nine months ended September 30, 2012, compared to $37.3 million provided by operating activities for the nine months ended September 30, 2011.  The increase in operating activities results primarily from an increase in revenues from increased production adjusted by cash utilized in connection with changes in working capital when comparing periods.  Cash utilized by changes in working capital for the nine months ended September 30, 2012 was $11.2 million compared to $5.8 million that was utilized by changes in working capital for the comparable period during 2011.  Decreases in working capital of $11.2 million for the nine months ended September 30, 2012 is comprised of increases in accounts receivable of $18.2 million offset by an increase in accounts payable and accrued liabilities (exclusive of capital accruals) of $6.8 million.  Decreases in working capital of $5.8 million for the nine month period ended September 30, 2011 is comprised of increases in accounts receivable of $6.1 million offset by an increase in accounts payable and accrued liabilities (exclusive of capital accruals) of $0.5 million.

Cash flows used in investing activities

Expenditures for development of oil and natural gas properties and natural gas plants are the primary use of our capital resources.  Net cash used in investing activities for the nine months ended September 30, 2012 was $204.9 million, compared to $110.9 million used in investing activities for the nine months ended September 30, 2011.  For the nine months ended September 30, 2012, cash used for the acquisition of oil and gas properties was $12.8 million, cash used for the development of oil and natural gas properties was $195.4 million including $12.0 million for a natural gas plant, offset by the sales proceeds from the Kern River property in the amount of $5.2 million which sold on August 31, 2012.

Cash provided by financing activities

Net cash provided by financing activities for the nine months ended September 30, 2012 was $115.0 million related to net borrowings on our line of credit in the amount of $115.7 million offset by deferred financing costs of $0.7 million.  Net cash provided by financing activities for the nine months ended September 30, 2011 was $73.7 million related to net borrowings on our line of credit in the amount of $76.7 million offset by deferred financing costs of $3.0 million.

Interest under our credit facility is generally determined by reference to either, at our option, (i) the London interbank offered rate, or LIBOR, for an elected interest period, plus an applicable margin between 1.75% to 2.75% depending on utilization level, or (ii) an alternate base rate (the highest of the administrative agent’s prime rate, the federal funds effective rate plus 0.5% or three-month LIBOR plus 1.00%), plus an applicable margin between 0.75% and 1.75%. Our credit facility provides for commitment fees of 0.375% to 0.50%, depending on utilization, and restricts, among other items, the payment of dividends, certain additional indebtedness, sale of assets, loans, certain investments and acquisitions.

New Accounting Pronouncements

For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, please refer to the Adopted and Recently Issued Accounting Pronouncements footnote in the Notes to the Consolidated Financial Statements.

Critical Accounting Policies and Estimates

Information regarding critical accounting policies and estimates is contained in Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2011.

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Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the nine month periods ended September 30, 2012 and 2011.  Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

Off-balance sheet arrangements

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

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Item 3.Quantitative and Qualitative Disclosures About Market Risk.

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

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

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

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

The result of oil market prices exceeding our swap prices or collar ceilings requires us to make payment for the settlement of our hedge derivatives, if owed by us, generally up to three business days before we receive market price cash payments from our customers. This could have a material adverse effect on our cash flows for the period between hedge settlement and payment for revenues earned.

The following table provides a summary of derivative contracts as of September 30, 2012.

Settlement Period	Derivative Instrument	Total Notional Amount (Bbl/Mmbtu)	Average Floor Price		Average Ceiling Price		Fair Market Value of Asset (Liability)
							(In thousands)
Oil
2012	Collar	233,868	$	90.00	$	106.05	$	370,200
	Swap	148,200	88.78		88.78		(583,345		)
2013	Collar	530,616	91.61		106.46		1,430,459
	Swap	915,417	88.08		88.08		(4,525,880		)
Gas
2012	Swap	969,308	3.33		3.33		11,175
2013	Swap	154,806	6.40		6.40		402,816
							$	(2,894,575	)

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Item 4.Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our management, including our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2012.  The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in SEC rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.  Based on the evaluation of our disclosure controls and procedures as of September 30, 2012, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended September 30, 2012 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.Legal Proceedings.

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other gas and oil producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. As of the date of this filing, there are no material pending or overtly threatened legal actions against us of which we are aware.

In June 2011, Frank H. Bennett, a co-manager of Bonanza Creek Oil Company, LLC (“BCOC”), Bonanza Creek Energy, LLC’s (“BCEC”) predecessor, and former chairman of BCEC, made a demand against Michael R. Starzer, our President and Chief Executive Officer, focusing on Mr. Starzer’s handling of the operation, accounting and finances of BCOC and BCEC primarily during the 2005-2006 time period. Mr. Bennett’s demands do not allege any wrongdoing by or claims against Bonanza Creek Energy, Inc. This matter was sent to arbitration in July 2011.

In July 2011, our board of directors formed a Special Litigation Committee comprised of three non-executive directors to conduct an investigation of the allegations. The Special Litigation Committee retained outside independent advisors and conducted an in-depth investigation. The Special Litigation Committee concluded that neither it nor its legal or financial advisors had found any evidence to support any of Mr. Bennett’s allegations. Our board of directors concluded that the allegations against Mr. Starzer are unsubstantiated and lack merit. However, there can be no assurance as to the ultimate outcome of the arbitration proceedings. An arbitration hearing commenced in July 2012 and it is not clear when a final decision will be rendered regarding the allegations or any potential recovery of legal fees. Mr. Starzer plans to continue to vigorously defend against Mr. Bennett’s claims. During the period from January 1, 2012 through September 30, 2012, the Company incurred approximately $2.5 million for the advancement of legal fees related to Mr. Bennett’s claims.

Item 1A. Risk Factors.

Our business faces many risks.  Any of the risk factors discussed in this Report, Item 1A of our 2011 Annual Report or our other SEC filings could have a material impact on our business, financial position or results of operations.  Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation.  During the three months ended September 30, 2012, there has been no material change to such risk factors.

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Item 2.Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3.Defaults Upon Senior Securities.

None.

Item 4.Mine Safety Disclosures.

Not applicable.

Item 5.Other Information.

None.

Item 6.Exhibits.

Exhibit No.	Description of Exhibit
10.1	Amendment No. 4, dated as of July 31, to the Credit Agreement among Bonanza Creek Energy, Inc., Key Bank National Association, as Administrative Agent, and the lenders party thereto (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the three months ended June 30, 2012 filed on August 13, 2012)
10.2	Amendment No. 5 & Agreement, dated as of October 30, 2012, to the Credit Agreement among Bonanza Creek Energy, Inc., KeyBank National Association, as Administrative Agent, and the lenders party thereto
31.1	Certification of the Principal Executive Officer pursuant to Rule 13a-14(a)
31.2	Certification of the Principal Financial Officer pursuant to Rule 13a-14(a)
32.1	Certification of the Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith)
32.2	Certification of the Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith)
101	The following materials from the Bonanza Creek Energy, Inc. Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, formatted in XBRL (Extensible Business Reporting Language) include (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Stockholders’ Equity, (iv) the Condensed Consolidated Statements of Cash Flows and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text. The information in Exhibit 101 is “furnished” and not “filed”, as provided in Rule 402 of Regulation S-T

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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.

		BONANZA CREEK ENERGY, INC.
Date:	November 8, 2012	By:	/s/ Michael R. Starzer
		Michael R. Starzer
		President and Chief Executive Officer
		(principal executive officer)
		By:	/s/ Wade E. Jaques
		Wade E. Jaques
		Chief Accounting Officer, Controller and Treasurer
		(principal financial officer)

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EX-10.2

Exhibit 10.2

AMENDMENT NO. 5

This AMENDMENT NO. 5 (the “Amendment”) dated as of October 30, 2012 (the “Effective Date”) is among Bonanza Creek Energy, Inc., a Delaware corporation (“Borrower”), the Guarantors (as defined in the Credit Agreement referred to below), the Lenders (as defined below), and KeyBank National Association, as Administrative Agent and as Issuing Lender (as such terms are defined below).

RECITALS

A.The Borrower is party to that certain Credit Agreement dated as of March 29, 2011 (as amended by Amendment No. 1 dated as of April 29, 2011, Amendment No. 2 & Agreement dated as of September 15, 2011, the Resignation, Consent and Appointment Agreement and Amendment Agreement dated as of April 6, 2012, Amendment No. 3 & Agreement dated as of May 8, 2012, Amendment No. 4 dated as of July 31, 2012 and as may be further amended, restated or otherwise modified from time to time, the “Credit Agreement”) among the Borrower, the lenders party thereto from time to time (the “Lenders”), and KeyBank National Association (as successor in interest to BNP Paribas), as administrative agent (in such capacity, the “Administrative Agent”) and as issuing lender (in such capacity, the “Issuing Lender”).  Each capitalized term defined in the Credit Agreement and used herein without definition shall have the meaning assigned to such term in the Credit Agreement, unless expressly provided to the contrary.

B.The Lenders wish to, subject to the terms and conditions of this Amendment, amend the Credit Agreement as provided herein.

THEREFORE, the Borrower, the Guarantors, the Administrative Agent, the Issuing Lender, and the Lenders hereby agree as follows:

Section 1.Defined Terms.  As used in this Amendment, each of the terms defined in the opening paragraph and the Recitals above shall have the meanings assigned to such terms therein.

Section 2.Other Definitional Provisions.  Article, Section, Schedule, and Exhibit references are to Articles and Sections of and Schedules and Exhibits to this Amendment, unless otherwise specified.  All references to instruments, documents, contracts, and agreements are references to such instruments, documents, contracts, and agreements as the same may be amended, supplemented, and otherwise modified from time to time, unless otherwise specified.  The words “hereof”, “herein”, and “hereunder” and words of similar import when used in this Amendment shall refer to this Amendment as a whole and not to any particular provision of this Amendment.  The term “including” means “including, without limitation,”.  Paragraph headings have been inserted in this Amendment as a matter of convenience for reference only and it is agreed that such paragraph headings are not a part of this Amendment and shall not be used in the interpretation of any provision of this Amendment.

Section 3.Amendments to Credit Agreement.

(a)Section 1.01 of the Credit Agreement is hereby amended by adding the following new defined terms in their alphabetically appropriate place:

“Intercreditor Agreement” means an Intercreditor Agreement on terms acceptable to the Majority Lenders between the Administrative Agent, in its capacity as agent for the Lenders, and the Second Lien Agent, as administrative agent for the Second Lien Lenders, and acknowledged and agreed to by the Borrower.

“Minimum Interest Coverage Ratio” means, as of such date of determination, the ratio of (a) the consolidated EBITDAX of the Borrower for the four fiscal quarter period then ended, to (b) cash interest expense of the Borrower and its consolidated Subsidiaries for the four (4) fiscal consecutive fiscal quarters then ended.

“Second Lien Agent” means any Second Lien Lender serving in the capacity as the administrative agent under the Second Lien Credit Agreement, or their respective successors or assigns, to the extent permitted under the Second Lien Credit Agreement and the Intercreditor Agreement.

“Second Lien Credit Agreement” means a Credit Agreement among the Borrower, the Second Lien Lenders, and the Second Lien Agent, as amended, restated, refinanced, supplemented or otherwise modified but only to the extent permitted under the terms of the Intercreditor Agreement; which Credit Agreement (a) shall (i) have a scheduled maturity date that is no earlier than March 15, 2017, (ii) have covenants and events of default that are no more restrictive in any material respect than those set forth in this Agreement and the other Loan Documents, (iii) have a bullet repayment of principal and not provide for scheduled amortization or mandatory prepayments of principal that are not Events of Default under this Agreement, (iv) be subject to the Intercreditor Agreement, and (v) otherwise be on terms and conditions reasonably acceptable to the Administrative Agent, and (b) the proceeds of which shall be used only (i) to finance the acquisition and development of Oil and Gas Properties, (ii) to finance capital expenditures, (iii) to repay Debt, and (iv) for other general corporate purposes.

“Second Lien Debt” means all Debt of the Borrower and any of its Subsidiaries in respect of the Second Lien Credit Agreement and the other Second Lien Loan Documents, which shall be subject to the terms of the Intercreditor Agreement.

“Second Lien Lenders” means the lenders party to the Second Lien Credit Agreement from time to time.

“Second Lien Loan Documents” means the Second Lien Credit Agreement, the promissory notes and security documents executed and delivered pursuant to the Second Lien Credit Agreement, the Intercreditor Agreement and each other agreement, instrument, certificate or document executed by the Borrower, any

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other Obligor, or any Obligor’s Subsidiary or any of their respective officers at any time in connection with the Second Lien Credit Agreement.

(b)The definition of “Loan Documents” in Section 1.01 of the Credit Agreement is hereby restated in its entirety as follows:

“Loan Documents” means this Agreement, the Notes, the Letter of Credit Documents, the Guaranties, the Security Instruments, the Intercreditor Agreement and each other agreement, instrument, certificate or document (other than the Second Lien Loan Documents) executed by the Borrower, any other Obligor, or any Obligor’s Subsidiary or any of their respective officers at any time in connection with this Agreement.

(c)Section 2.02(e) is hereby amended by replacing the reference to “Section 6.02(g)” with a reference to “Sections 6.02(g) and 6.02(i)”.

(d)Section 5.06 of the Credit Agreement is hereby amended by deleting the “and” at the end of clause (p), moving clause (q) thereof to clause (r) and inserting the new clause (q) to provide as follows:

(q)Notices Delivered Under the Second Lien Credit Agreement.  Concurrently with the delivery of any notice or other information to the Second Lien Agent or the Second Lien Lenders, a copy of such notice or other information to the Administrative Agent or the Lenders, as appropriate; and

(e)Section 6.01 of the Credit Agreement is hereby amended by deleting the “and” at the end of clause (p), moving clause (q) thereof to clause (r) and inserting the new clause (q) to provide as follows:

(q)Liens securing Second Lien Debt to the extent permitted under the Intercreditor Agreement; provided that, subject to the terms of the Intercreditor Agreement, (i) the collateral with respect to which a Lien is granted as security for the Second Lien Debt shall be limited to the Collateral hereunder and (ii) the Liens securing the Obligations hereunder shall be senior to the Liens securing the Second Lien Debt; and

(f)Section 6.02 of the Credit Agreement is hereby amended by deleting clauses (g) and (h) and replacing them with the following new clauses (g) and (h):

(g)Bond Debt; provided that, (i) the aggregate outstanding principal amount of all such Bond Debt and Bond Refinancing Debt may not exceed $250,000,000 at any time, (ii) the Borrowing Base then in effect on funding of any such Bond Debt shall automatically reduce by an amount equal to 25% of the aggregate principal amount (without giving effect to any original issue discount) of such issuance (which reduction shall be effective on the next succeeding Business Day after such funding and such reduced Borrowing

3

Base shall remain in effect until the date the Borrowing Base is otherwise redetermined pursuant to Section 2.02), and (iii) either (A) no Second Lien Debt shall be outstanding or (B) the proceeds of the Bond Debt shall be used to repay the Second Lien Debt in full;

(h)Bond Refinancing Debt; provided that, (i) the aggregate outstanding principal amount of all Bond Debt and Bond Refinancing Debt may not exceed $250,000,000 at any time and (ii) no Second Lien Debt shall be outstanding; and

(g)Section 6.02 of the Credit Agreement is hereby amended by moving clause (i) thereof to clause (j) and inserting the new clause (i) to provide as follows:

(i)Second Lien Debt; provided that, (i) the aggregate principal amount of all such Second Lien Debt may not exceed $150,000,000 at any time, (ii) the Borrowing Base then in effect on the funding of any such Second Lien Debt shall automatically reduce by an amount equal to 25% of the aggregate principal amount of such advance under the Second Lien Credit Agreement (which reduction shall be effective on the next succeeding Business Day after such funding and such reduced Borrowing Base shall remain in effect until the date the Borrowing Base is otherwise redetermined pursuant to Section 2.02), and (iii) no Bond Debt or Bond Refinancing Debt shall be outstanding; and

(h)The Credit Agreement is hereby amended by adding the following new Section 6.20:

Section 6.20Minimum Interest Coverage Ratio.  From and after the effective date of the Second Lien Credit Agreement, Borrower shall not permit the Minimum Interest Coverage Ratio as of each fiscal quarter end of the Borrower to be less than 3.00 to 1.00.

(i)The Credit Agreement is hereby amended by adding the following new Section 6.21:

Section 6.21Second Lien Debt.  Except as otherwise permitted by the terms of the Intercreditor Agreement, none of the Borrower nor any Subsidiary of a Borrower shall (a) make any optional, mandatory or scheduled payments on account of principal (whether by redemption, purchase, retirement, defeasance, set off or otherwise), interest, premiums and fees in respect of the Second Lien Debt, or (b) amend, supplement, refinance or otherwise modify the terms of the Second Lien Debt, the Second Lien Credit Agreement or any other Second Lien Loan Document.

(j)Section 7.01 of the Credit Agreement is hereby amended by deleting the “or” at the end of clause (k), replacing the “.” at the end of clause (l) with “; or” and adding the following two new clauses (m) and (n):

(m)An “Event of Default” under the Second Lien Credit Agreement shall have occurred; or

4

(n)From and after the effective date of the Second Lien Credit Agreement, the Intercreditor Agreement shall cease to be effective (other than pursuant to the terms provided therein) or otherwise shall cease to be a legal, valid and binding agreement enforceable against the holders of any Debt under the Second Lien Credit Agreement in any material respect.

(k)Section 7.06(c) of the Credit Agreement is hereby amended is hereby by adding the following new proviso to the end thereof:

(c)   ; provided that, from and after the effective date of the Second Lien Credit Agreement, the remainder shall instead be paid to the Second Lien Agent to the extent required under the Intercreditor Agreement.

(l)The Credit Agreement is hereby amended by adding the following new Section 9.09:

Section 9.09Intercreditor Agreement. The Administrative Agent is hereby authorized on behalf of the Secured Parties to enter into the Intercreditor Agreement. Each Secured Party, by receiving the benefits thereunder and of the Collateral under the Security Instruments, acknowledges and agrees to the terms of the Intercreditor Agreement and agrees that the terms thereof shall be binding on such Secured Party and its respective successors and assigns, as if each were a party thereto.

Section 4.Borrowing Base.  Subject to the terms of this Amendment, the Lenders and the Borrower hereby agree that upon the Effective Date, the Borrowing Base shall be increased to $325,000,000, and the amount of such Borrowing Base shall remain in effect until the Borrowing Base is redetermined pursuant to Section 2.02 of the Credit Agreement.

Section 5.Representations and Warranties.  The Borrower and each Guarantor represents and warrants that: (a) the representations and warranties contained in the Credit Agreement and the representations and warranties contained in the other Loan Documents are true and correct in all material respects on and as of the Effective Date as if made on and as of such date, except to the extent that any such representation or warranty expressly relates solely to an earlier date, in which case such representation or warranty is true and correct in all material respects as of such earlier date; (b) no Default has occurred and is continuing; (c) the execution, delivery and performance of this Amendment are within the corporate power and authority of such Person and have been duly authorized by appropriate corporate action and proceedings; (d) this Amendment constitutes the legal, valid, and binding obligation of such Person enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws affecting the rights of creditors generally and general principles of equity; (e) there are no governmental or other third party consents, licenses and approvals required in connection with the execution, delivery, performance, validity and enforceability of this Amendment; (f) the Liens under the Security Instruments are valid and subsisting and secure Borrower’s obligations under the Loan Documents; and (g) as to each Guarantor, it has no defenses to the enforcement of its Guaranty.

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Section 6.Conditions to Effectiveness.

(a)This Amendment shall become effective on the Effective Date and enforceable against the parties hereto upon the occurrence of the following conditions precedent:

(i)The Administrative Agent shall have received multiple original counterparts, as requested by the Administrative Agent, of this Amendment duly and validly executed and delivered by duly authorized officers of the Borrower, the Guarantors, the Issuing Lender and the Lenders.

(ii)No Default shall have occurred and be continuing as of the Effective Date.

(iii)The representations and warranties in this Amendment shall be true and correct in all material respects.

(iv)The Borrower shall have paid all costs and expenses which have been invoiced and are payable pursuant to Section 10.04 of the Credit Agreement.

Section 7.Acknowledgments and Agreements.

(a)The Borrower acknowledges that on the date hereof all Obligations are payable without defense, offset, counterclaim or recoupment.

(b)The Administrative Agent, the Issuing Lender and the Lenders hereby expressly reserve all of their rights, remedies, and claims under the Loan Documents.  Nothing in this Amendment shall constitute a waiver or relinquishment of (i) any Default or Event of Default under any of the Loan Documents, (ii) any of the agreements, terms or conditions contained in any of the Loan Documents, (iii) any rights or remedies of the Administrative Agent, the Issuing Lender or any Lender with respect to the Loan Documents, or (iv) the rights of the Administrative Agent, the Issuing Lender or any Lender to collect the full amounts owing to them under the Loan Documents.

(c)Each of the Borrower, the Administrative Agent, the Issuing Lender and the Lenders does hereby adopt, ratify, and confirm the Credit Agreement, as amended hereby, and acknowledges and agrees that the Credit Agreement, as amended hereby, is and remains in full force and effect, and the Borrower acknowledges and agrees that its liabilities and obligations under the Credit Agreement, as amended hereby, are not impaired in any respect by this Amendment.

(d)From and after the Effective Date, all references to the Credit Agreement and the Loan Documents shall mean such Credit Agreement and such Loan Documents as amended by this Amendment.

(e)This Amendment is a Loan Document for the purposes of the provisions of the other Loan Documents.  Without limiting the foregoing, any breach of representations, warranties, and covenants under this Amendment shall be a Default or Event of Default, as applicable, under the Credit Agreement.

6

Section 8.Reaffirmation of Guaranty.  Each Guarantor hereby ratifies, confirms, acknowledges and agrees that its obligations under its Guaranty are in full force and effect and that such Guarantor continues to unconditionally and irrevocably guarantee the full and punctual payment, when due, whether at stated maturity or earlier by acceleration or otherwise, of all of the Obligations, as such Obligations may have been amended by this Amendment, and its execution and delivery of this Amendment does not indicate or establish an approval or consent requirement by the Guarantor in connection with the execution and delivery of amendments, consents or waivers to the Credit Agreement or any of the other Loan Documents.

Section 9.Counterparts.  This Amendment may be signed in any number of counterparts, each of which shall be an original and all of which, taken together, constitute a single instrument.  This Amendment may be executed by facsimile signature or signature delivered by other electronic means and all such signatures shall be effective as originals.

Section 10.Successors and Assigns.  This Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted pursuant to the Credit Agreement.

Section 11.Invalidity.  In the event that any one or more of the provisions contained in this Amendment shall for any reason be held invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision of this Amendment.

Section 12.Governing Law.  This Amendment shall be deemed to be a contract made under and shall be governed by and construed in accordance with the laws of the State of Texas.

Section 13.RELEASE.  THE BORROWER ACKNOWLEDGES THAT ON THE DATE HEREOF ALL OBLIGATIONS ARE PAYABLE WITHOUT DEFENSE, OFFSET, COUNTERCLAIM OR RECOUPMENT.  IN ADDITION, EACH OF THE BORROWER, THE GUARANTORS AND EACH OF THEIR RESPECTIVE SUBSIDIARIES (FOR THEMSELVES AND THEIR RESPECTIVE SUCCESSORS, AGENTS, ASSIGNS, TRANSFEREES, OFFICERS, DIRECTORS, EMPLOYEES, SHAREHOLDERS, ATTORNEYS AND AGENTS) HEREBY RELEASES ANY AND ALL CLAIMS, CAUSES OF ACTION OR OTHER DISPUTES IT MAY HAVE AGAINST THE ADMINISTRATIVE AGENT, THE ISSUING LENDER, ANY OF THE LENDERS, LEGAL COUNSEL TO THE ADMINISTRATIVE AGENT, THE ISSUING LENDER OR ANY OF THE LENDERS, CONSULTANTS HIRED BY ANY OF THE FOREGOING, OR ANY OF THEIR RESPECTIVE AFFILIATES, SUBSIDIARIES, SHAREHOLDERS, AGENTS, DIRECTORS, OFFICERS, EMPLOYEES, REPRESENTATIVES, SUCCESSORS OR ASSIGNS OF ANY KIND OR NATURE ARISING OUT OF, RELATED TO, OR IN ANY WAY CONNECTED WITH, THE CREDIT AGREEMENT OR THE LOAN DOCUMENTS, IN EACH CASE WHICH MAY HAVE ARISEN ON OR BEFORE THE DATE OF THIS AMENDMENT.  EACH OF THE BORROWER, THE GUARANTORS AND THEIR RESPECTIVE SUBSIDIARIES HEREBY ACKNOWLEDGES THAT IT HAS READ THIS AMENDMENT AND HAS CONFERRED WITH ITS COUNSEL AND ADVISORS REGARDING ITS CONTENT, INCLUDING THIS SECTION 13, AND IS FREELY AND VOLUNTARILY ENTERING INTO THIS AMENDMENT, AND HEREBY AGREES TO WAIVE ANY CLAIM THAT THE TERMS

7

OF THIS AMENDMENT (INCLUDING, WITHOUT LIMITATION, THE RELEASES CONTAINED HEREIN) ARE INVALID OR OTHERWISE UNENFORCEABLE.

Section 14.Entire Agreement.  THIS AMENDMENT, THE CREDIT AGREEMENT AS AMENDED BY THIS AMENDMENT, THE NOTES, AND THE OTHER LOAN DOCUMENTS CONSTITUTE THE ENTIRE UNDERSTANDING AMONG THE PARTIES HERETO WITH RESPECT TO THE SUBJECT MATTER HEREOF AND SUPERSEDE ANY PRIOR AGREEMENTS, WRITTEN OR ORAL, WITH RESPECT THERETO.

THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES.

[signature pages follow]

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EXECUTED effective as of the date first above written.

BORROWER:	BONANZA CREEK ENERGY, INC.
	By:	/s/ Michael R. Starzer
		Michael R. Starzer
		President & Chief Executive Officer
GUARANTORS:
	BONANZA CREEK ENERGY OPERATING COMPANY, LLC
	By:	Bonanza Creek Energy, Inc., its Manager
	By:	/s/ Michael R. Starzer
		Michael R. Starzer
		President & Chief Executive Officer
	BONANZA CREEK ENERGY RESOURCES,
	LLC
	By:	/s/ Michael R. Starzer
		Michael R. Starzer
		President & Chief Executive Officer
	BONANZA CREEK ENERGY MIDSTREAM,
	LLC
	By:	/s/ Michael R. Starzer
		Michael R. Starzer
		President & Chief Executive Officer

Signature Page to Amendment No. 5

Bonanza Creek Energy, Inc.

BONANZA CREEK ENERGY UPSTREAM
LLC
By:	/s/ Michael R. Starzer
	Michael R. Starzer
	President & Chief Executive Officer
HOLMES EASTERN COMPANY, LLC
By:	/s/ Michael R. Starzer
	Michael R. Starzer
	President & Chief Executive Officer

Signature Page to Amendment No. 5

Bonanza Creek Energy, Inc.

ADMINISTRATIVE AGENT/
ISSUING LENDER/LENDER:	KEYBANK NATIONAL ASSOCIATION, as Administrative Agent, Issuing Lender, and a Lender
	By:	/s/ Chulley Bogle
	Name:	Chulley Bogle
	Title:	Vice President

Signature Page to Amendment No. 5

Bonanza Creek Energy, Inc.

LENDER:	COMPASS BANK, as a Lender
	By:	/s/ James Neblett
	Name:	James Neblett
	Title:	Vice President

Signature Page to Amendment No. 5

Bonanza Creek Energy, Inc.

LENDER:	SOCIÉTÉ GÉNÉRALE, as a Lender
	By:	/s/ Elena Robciuc
	Name:	Elena Robciuc
	Title:	Director

Signature Page to Amendment No. 5

Bonanza Creek Energy, Inc.

LENDER:	BMO HARRIS FINANCING, INC., as a Lender
	By:	/s/ Gumaro Tijerina
	Name:	Gumaro Tijerina
	Title:	Director

Signature Page to Amendment No. 5

Bonanza Creek Energy, Inc.

LENDER:	WELLS FARGO BANK. N.A., as a Lender
	By:	/s/ Jonathan Herrick
	Name:	Jonathan Herrick
	Title:	Assistant Vice President

Signature Page to Amendment No. 5

Bonanza Creek Energy, Inc.

LENDER:	JPMORGAN CHASE BANK, N.A., as a Lender
	By:	/s/ David Morris
	Name:	David Morris
	Title:	Authorized Officer

Signature Page to Amendment No. 5

Bonanza Creek Energy, Inc.

LENDER:	ROYAL BANK OF CANADA, as a Lender
	By:	/s/ Mark Lumpkin, Jr.
	Name:	Mark Lumpkin, Jr.
	Title:	Authorized Signatory

Signature Page to Amendment No. 5

Bonanza Creek Energy, Inc.

LENDER:	CADENCE BANK, N.A., as a Lender
	By:	/s/ Eric Broussard
	Name:	Eric Broussard
	Title:	Senior Vice President

Signature Page to Amendment No. 5

Bonanza Creek Energy, Inc.

LENDER:	IBERIABANK, as a Lender
	By:	/s/ Cameron D. Jones
	Name:	Cameron D. Jones
	Title:	Vice President

Signature Page to Amendment No. 5

Bonanza Creek Energy, Inc.

LENDER:	THE BANK OF NOVA SCOTIA, as a Lender
	By:	/s/ Terry Donovan
	Name:	Terry Donovan
	Title:	Managing Director

Signature Page to Amendment No. 5

Bonanza Creek Energy, Inc.

EX-31.1

Exhibit 31.1

CERTIFICATION OF THE PRINCIPAL EXECUTIVE OFFICER PURSUANT TO RULE 13a-14(a)

I, Michael R. Starzer, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2012 of Bonanza Creek Energy, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 8, 2012
	/s/ Michael R. Starzer
	Michael R. Starzer President and Chief Executive Officer of Bonanza Creek Energy, Inc.

EX-31.2

Exhibit 31.2

CERTIFICATION OF THE PRINCIPAL FINANCIAL OFFICER PURSUANT TO RULE 13a-14(a)

I, Wade E. Jaques, certify that:

1.I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2012 of Bonanza Creek Energy, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 8, 2012
	/s/ Wade E. Jaques
	Wade E. Jaques Chief Accounting Officer, Controller and Treasurer of Bonanza Creek Energy, Inc.

EX-32.1

Exhibit 32.1

Certification of the Principal Executive Officer

Pursuant to 18 U.S.C. Section 1350,

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Bonanza Creek Energy, Inc. (the “Company”) on Form 10-Q for the period ended September 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael R. Starzer, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 8, 2012
	/s/ Michael R. Starzer
	Michael R. Starzer President and Chief Executive Officer of Bonanza Creek Energy, Inc.

EX-32.2

Exhibit 32.2

Certification of the Principal Financial Officer

Pursuant to 18 U.S.C. Section 1350,

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Bonanza Creek Energy, Inc. (the “Company”) on Form 10-Q for the period ended September 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Wade E. Jaques, Vice President, Chief Accounting Officer, Controller and Treasurer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: November 8, 2012
	/s/ Wade E. Jaques
	Wade E. Jaques Chief Accounting Officer, Controller and Treasurer of Bonanza Creek Energy, Inc.

XML

FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION: (Details 3) (Commodity derivatives)	Sep. 30, 2012 bblpermonth
October 1- December 31, 2012
Derivative contract
Notional Volume	77,956
October 1- December 31, 2012 | $88.78
Derivative contract
Notional Volume	49,400
Price (in dollars per unit)	88.78
October 1- December 31, 2012 | $3.33
Derivative contract
Notional Volume	323,103
Price (in dollars per unit)	3.33
January 1 - December 31, 2013
Derivative contract
Notional Volume	44,218
January 1 - December 31, 2013 | $88.08
Derivative contract
Notional Volume	76,285
Price (in dollars per unit)	88.08
January 1 - October 31, 2013 | $6.40
Derivative contract
Notional Volume	15,481
Price (in dollars per unit)	6.40
Average Floor | October 1- December 31, 2012
Derivative contract
Price (in dollars per unit)	90.00
Average Floor | January 1 - December 31, 2013
Derivative contract
Price (in dollars per unit)	91.61
Average Ceiling | October 1- December 31, 2012
Derivative contract
Price (in dollars per unit)	106.05
Average Ceiling | January 1 - December 31, 2013
Derivative contract
Price (in dollars per unit)	106.46

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ACQUISTIONS AND DIVESTITURES: (Details) (Acquired leases in Wattenberg field, USD $)	0 Months Ended
	Jul. 31, 2012 acre
Acquired leases in Wattenberg field
ACQUISTIONS
Area of acquired leases (in acres)	5,600
Cash paid	$ 12,000,000
Potential consideration payable	12,000,000
Period for potential payment of consideration	4 years
Purchase price	$ 57,000,000

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SUBSEQUENT EVENTS: (Details) (USD $)	9 Months Ended				0 Months Ended	3 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012 Senior secured revolving credit agreement	Oct. 30, 2012 Subsequent event Senior secured revolving credit agreement	Oct. 11, 2012 Subsequent event Liberty Energy, LLC	Sep. 30, 2012 Subsequent event Liberty Energy, LLC
SUBSEQUENT EVENTS
Non-operating interest in the Sargent field in California (as a percent)					50.00%
Sale amount					$ 3,200,000
Impairment recorded to write the field down to the expected sales price	1,916,690	4,067,023				460,000
Borrowing base			$ 245,000,000	$ 325,000,000

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ACQUISTIONS AND DIVESTITURES:

9 Months Ended

Sep. 30, 2012

ACQUISTIONS AND DIVESTITURES:

ACQUISTIONS AND DIVESTITURES:

3. ACQUISTIONS AND DIVESTITURES:

On July 31, 2012, the Company acquired leases to approximately 5,600 net acres in the Wattenberg field from the State of Colorado, State Board of Land Commissioners. The Company paid approximately $12 million at closing and will pay approximately $12 million on July 31st of each of the next four years. These future payments were discounted based on our effective borrowing rate to arrive at the purchase price of $57,000,000. These future payments are secured by a letter of credit and interest will be imputed on the future payments.

During June of 2012, the Company began marketing, with an intent to sell, all of its oil and gas properties in California. Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted and a measurement for impairment is performed to expense any excess of carrying value over fair value less costs to sell. The Company determined that its intent to sell these properties qualifies for discontinued operations and, on August 31, 2012, the Company sold a portion of the properties for approximately $5.1 million and recorded a gain on the sale of oil and gas properties in the amount of $4.3 million related to this transaction. The carrying amounts of the major classes of assets and liabilities related to the operation of the remaining properties that are held for sale as of September 30, 2012 and December 31, 2011 are presented below:

	As of September 30, 2012			As of December 31, 2011
PROPERTY AND EQUIPMENT:
Oil and gas properties, successful efforts method:
Proved properties	$	7,799,582		$	13,060,597
Unproved properties	32,013			32,013
Wells in progress	30,629			167,198
Total property and equipment	7,862,224			13,259,808
Less accumulated depletion and depreciation	(2,823,942		)	(3,364,300		)
Net property and equipment	$	5,038,282		$	9,895,508
ASSET RETIREMENT OBLIGATIONS	$	769,700		$	975,562

Total revenues and costs and expenses, and the income associated with the operation of the oil and gas properties held for sale for the three and nine month periods ended September 30, 2012 and 2011 are presented below.

	Three Months Ended September 30			Three Months Ended September 30			Nine MonthsEnded September 30			Nine Months Ended September 30
	2012			2011			2012			2011
NET REVENUES:
Oil and gas sales	$	1,274,906		$	1,458,198		$	5,000,665		$	4,927,493
OPERATING EXPENSES:
Lease operating	451,795			795,428			1,853,085			2,419,715
Severance and ad valorem taxes	8,809			(1,000		)	124,298			81,449
Exploration	6,219			400			17,008			6,995
Depreciation, depletion and amortization	570,488			974,035			2,149,478			2,610,576
Impairment of proved properties	1,648,190			3,443,984			1,648,190			3,443,984
TOTAL COSTS AND EXPENSES	2,685,501			5,212,847			5,792,059			8,562,719
LOSS FROM OPERATIONS ASSOCIATED WITH OIL AND GAS PROPERTIES HELD FOR SALE	$	(1,410,595	)	$	(3,754,649	)	$	(791,394	)	$	(3,635,226	)

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COMMITMENTS AND CONTINGENT LIABILITIES: (Details) (USD $)	Sep. 30, 2012
Office leases
2012	$ 297,265
2013	13,098,696
2014	13,085,727
2015	13,111,243
2016 and thereafter	136,535,730
Total	176,128,661
Office Leases
Office leases
2012	297,265
2013	1,098,709
2014	1,085,740
2015	1,111,256
2016 and thereafter	2,235,743
Total	5,828,713
Line of Credit
Office leases
2016 and thereafter	122,300,000
Total	122,300,000
Wattenberg Field Lease Acquisition
Office leases
2013	11,999,987
2014	11,999,987
2015	11,999,987
2016 and thereafter	11,999,987
Total	$ 47,999,948

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SENIOR SECURED REVOLVING CREDIT FACILITY: (Details) (Revolver, USD $) In Millions, unless otherwise specified			9 Months Ended					9 Months Ended
	Sep. 30, 2012	May 08, 2012	Sep. 30, 2012 LIBOR	Sep. 30, 2012 Bank Prime Rate	Sep. 30, 2012 Minimum	Sep. 30, 2012 Minimum LIBOR	Sep. 30, 2012 Minimum Bank Prime Rate	Sep. 30, 2012 Maximum	Sep. 30, 2012 Maximum LIBOR	Sep. 30, 2012 Maximum Bank Prime Rate
Senior Secured Revolving Credit Facility
Maximum borrowing capacity		$ 600
Basis of interest rate			LIBOR	Bank Prime Rate
Interest rate margin (as a percent)						1.75%	0.75%		2.75%	1.75%
Borrowing base	245
Reduction in borrowing base due to issue of letter of credit	$ 48
Commitment fees (as a percent)					0.375%			0.50%

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COMMITMENTS AND CONTINGENT LIABILITIES: (Details 2) (USD $) In Millions, unless otherwise specified		9 Months Ended
	Jul. 31, 2011 Current President and Chief Executive Officer vs. former Chairman of BCEC director	Sep. 30, 2012 Mr. Bennett's claims
Legal Proceedings
Number of non-executive directors in special litigation committee	3
Expenses related to litigation		$ 2.5

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FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION: (Details) (Recurring, Commodity derivative, USD $)	Sep. 30, 2012	Dec. 31, 2011
Level 2
Financial assets and liabilities accounted for at fair value
Derivative assets	$ 825,074	$ 1,094,055
Derivative liabilities	6,159,571	6,740,213
Level 3
Financial assets and liabilities accounted for at fair value
Derivative assets	2,439,922	881,822
Derivative liabilities		$ 1,115,595

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BASIS OF PRESENTATION:

9 Months Ended

Sep. 30, 2012

BASIS OF PRESENTATION:

BASIS OF PRESENTATION:

2. BASIS OF PRESENTATION:

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The quarterly financial statements included herein do not necessarily include all of the disclosures as may be required under generally accepted accounting principles. The readers of these quarterly financial statements should also read the audited consolidated financial statements and related notes of BCEI that were included in BCEI’s Annual Report on Form 10-K filed with the SEC on March 22, 2012. These consolidated financial statements include all of the adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and results of operations. All such adjustments are of a normal recurring nature only. The results of operations for the quarterly periods are not necessarily indicative of the results to be expected for the full fiscal year.

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

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

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

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

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FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION: (Details 2) (Commodity derivatives, USD $)	9 Months Ended
	Sep. 30, 2012
Commodity derivatives
Derivative Asset
Beginning net asset (liability) balance	$ 881,822
Net increase in fair value	(654,780)
Net realized (gain) on settlement	(231,511)
New derivatives	411,178
Ending net asset (liability) balance	406,709
Derivative (Liability)
Beginning net asset (liability) balance	(1,115,595)
Net increase in fair value	4,978,506
Net realized (gain) on settlement	(233,412)
New derivatives	(1,596,286)
Ending net asset (liability) balance	$ 2,033,213

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CONSOLIDATED BALANCE SHEETS (USD $)	Sep. 30, 2012	Dec. 31, 2011
CURRENT ASSETS:
Cash and cash equivalents	$ 4,845,583	$ 2,089,674
Accounts receivable:
Oil and gas sales	29,520,522	17,850,719
Other	12,079,986	5,696,825
Prepaid expenses and other	1,515,475	1,868,016
Inventory of oilfield equipment	2,014,418	3,324,368
Derivative asset	2,714,219	1,297,403
Total current assets	52,690,203	32,127,005
OIL AND GAS PROPERTIES-using the successful efforts method of accounting:
Proved properties	718,962,011	547,878,188
Unproved properties	72,928,364	15,848,703
Wells in progress	69,819,751	23,783,142
OIL AND GAS PROPERTIES-using the successful efforts method of accounting	861,710,126	587,510,033
Less: accumulated depreciation, depletion and amortization	(66,199,440)	(26,759,043)
OIL AND GAS PROPERTIES-net, using the successful efforts method of accounting	795,510,686	560,750,990
NATURAL GAS PLANT	67,648,720	56,910,232
Less: accumulated depreciation	(2,820,328)	(1,286,129)
NATURAL GAS PLANT-net	64,828,392	55,624,103
PROPERTY AND EQUIPMENT	4,186,352	1,983,037
Less: accumulated depreciation	(611,272)	(128,731)
PROPERTY AND EQUIPMENT-net	3,575,080	1,854,306
Oil and gas properties held for sale less accumulated depreciation, depletion, and amortization	5,038,282	9,895,508
LONG-TERM DERIVATIVE ASSET	550,777	678,474
OTHER ASSETS, net	3,344,385	3,418,626
TOTAL ASSETS	925,537,805	664,349,012
CURRENT LIABILITIES:
Accounts payable and accrued expenses	62,993,900	27,068,326
Oil and gas revenue distribution payable	9,733,852	6,185,983
Contractual obligation for land acquisition	11,999,877
Derivative liability	5,339,006	5,276,633
Total current liabilities	90,066,635	38,530,942
LONG-TERM LIABILITIES:
Bank revolving credit	122,300,000	6,600,000
Contractual obligation for land acquisition	33,081,306
Ad valorem taxes	7,547,363	3,014,023
Derivative liability	820,565	2,579,175
Deferred income taxes, net	100,160,507	79,603,633
Asset retirement obligations	7,196,824	6,039,723
TOTAL LIABILITIES	361,173,200	136,367,496
COMMITMENTS AND CONTINGENCIES (Notes 7 and 8)
STOCKHOLDERS' EQUITY:
Preferred stock, $.001 par value, 25,000,000 shares authorized, 0 outstanding
Common stock, $.001 par value, 225,000,000 shares authorized, 40,057,248 and 39,477,584 issued and outstanding, respectively	40,057	39,478
Additional paid-in capital	518,321,950	515,412,583
Retained earnings	46,002,598	12,529,455
Total stockholders' equity	564,364,605	527,981,516
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 925,537,805	$ 664,349,012

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 33,473,143	$ 12,868,017
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	43,900,774	21,083,067
Impairment of oil and gas properties	1,916,690	4,067,023
Deferred income taxes	20,556,874	11,463,569
Non-cash stock compensation	2,912,248	132,720
Exploration	7,378,612
Amortization of deferred financing costs	501,315	702,490
Valuation (increase) decrease in commodity derivatives	(2,985,356)	(7,095,912)
Gain on sale of oil and gas properties	(4,279,998)
Other	70,563	92,352
(Increase) decrease in operating assets:
Accounts receivable	(18,152,964)	(6,060,781)
Prepaid expenses and other assets	352,541	(182,034)
(Decrease) increase in operating liabilities:
Accounts payable and accrued liabilities	7,149,501	534,255
Settlement of asset retirement obligations	(146,125)	(138,614)
Net cash provided by operating activities	92,647,818	37,333,432
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of oil and gas properties	5,212,000
Acquisition of oil and gas properties	(12,809,268)	(1,383,009)
Exploration and development of oil and gas properties	(183,357,438)	(91,906,848)
Natural gas plant capital expenditures	(12,009,040)	(18,063,482)
Proceeds from note receivable		986,906
Decrease in restricted cash	252,580
Additions to property and equipment-non oil and gas	(2,203,315)	(485,176)
Net cash used in investing activities	(204,914,481)	(110,851,609)
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in bank revolving credit	115,700,000	145,900,000
Payment on bank revolving credit		(69,200,000)
Deferred financing costs	(677,428)	(3,029,254)
Net cash provided by financing activities	115,022,572	73,670,746
NET INCREASE IN CASH AND CASH EQUIVALENTS	2,755,909	152,569
CASH AND CASH EQUIVALENTS:
Beginning of period	2,089,674
End of period	4,845,583	152,569
SUPPLEMENTAL CASH FLOW DISCLOSURE:
Cash paid for interest	1,224,331	1,876,866
Cash paid for income taxes	185,765
Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition	36,857,282	14,135,675
Contractual obligation for land acquisition	$ 45,081,183

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STOCKHOLDERS' EQUITY: (Details) (USD $)	3 Months Ended		9 Months Ended				1 Months Ended	9 Months Ended		0 Months Ended	1 Months Ended	9 Months Ended		0 Months Ended	15 Months Ended	0 Months Ended	3 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012 MIP BCEI	Dec. 23, 2010 MIP BCEI	Dec. 31, 2010 MIP BCEI Restricted shares	Sep. 30, 2012 MIP BCEI Restricted shares	Sep. 30, 2012 BCEC Management Incentive Plan	Aug. 15, 2012 BCEI Long Term Incentive Plan Restricted shares	Jun. 30, 2012 BCEI Long Term Incentive Plan Restricted shares	Sep. 30, 2012 BCEI Long Term Incentive Plan Restricted shares	Jun. 14, 2012 BCEI Long Term Incentive Plan Restricted shares	Aug. 03, 2012 BCEI Long Term Incentive Plan Restricted shares Member of Board of Directors Service for the period 2011-2012 director	Jun. 30, 2012 BCEI Long Term Incentive Plan Restricted shares Member of Board of Directors Service for the period 2011-2012	Aug. 03, 2012 BCEI Long Term Incentive Plan Restricted shares Member of Board of Directors Service for the period 2012-2013 director	Sep. 30, 2012 BCEI Long Term Incentive Plan Restricted shares Member of Board of Directors Service for the period 2012-2013
STOCKHOLDERS' EQUITY
Shares available under the plan						10,000
Shares granted							437,787		73,197	25,000	540,000			16,626		16,908
Share price (in dollars per share)						$ 17.00				$ 19.03			$ 15.38	$ 18.04		$ 18.04
Vesting period							3 years			3 years
Non-cash stock compensation	$ 1,445,910	$ 132,720	$ 2,912,248	$ 132,720	$ 1,822,000
Unrecognized compensation costs								5,372,000
Unrecognized compensation costs recognition period								2 years 3 months				2 years 8 months 12 days
Vesting portion of shares										0.33		0.33
Number of independent members of Board of Directors														4		4
Non-cash compensation expense															$ 300,000		$ 73,000

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COMMITMENTS AND CONTINGENT LIABILITIES: (Tables)

9 Months Ended

Sep. 30, 2012

COMMITMENTS AND CONTINGENT LIABILITIES:

Schedule of future minimum noncancelable lease payments

	Office Leases		Wattenberg FieldLease Acquisition		Line of Credit		Total
2012	$	297,265	$	—	—		$	297,265
2013	1,098,709		11,999,987		—		13,098,696
2014	1,085,740		11,999,987		—		13,085,727
2015	1,111,256		11,999,987		—		13,111,243
2016 and thereafter	2,235,743		11,999,987		122,300,000		136,535,730
	$	5,828,713	$	47,999,948	$	122,300,000	$	176,128,661

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IMPAIRMENT OF PROVED PROPERTIES: (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
IMPAIRMENT OF PROVED PROPERTIES
Impairment of proved properties	$ 268,500	$ 623,039	$ 268,500	$ 623,039
Non-core field in Southern Arkansas
IMPAIRMENT OF PROVED PROPERTIES
Impairment of proved properties			300,000
Number of non-core fields			1
Oil and gas properties in California
IMPAIRMENT OF PROVED PROPERTIES
Impairment of proved properties	$ 1,648,190	$ 3,443,984	$ 1,648,190	$ 3,443,984

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ORGANIZATION AND BUSINESS: (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended
	Dec. 31, 2010	Dec. 23, 2010
Laminar
Organization and Business
Percentage of ownership interest distributed		12.91%
Management and employees of BCEC
Organization and Business
Percentage of ownership interest distributed		3.14%
HEC
Organization and Business
Percentage of ownership interest in reporting entity		5.77%
Proceeds from sale of common stock exchanged for ownership interest		59
BCEC
Organization and Business
Percentage of ownership interest in reporting entity		21.55%
Retirement of second lien term loan, senior subordinated notes and a related party note payable, and portion of outstanding principal balance of bank revolving credit facility	182
Reduction in outstanding line of credit facility	29
Outstanding amount of line of credit facility	55.4
Black Bear and clients of AIMCO
Organization and Business
Percentage of ownership interest in reporting entity		72.68%
Common stock	$ 265
BCOC
Organization and Business
Percentage of ownership interest in reporting entity		5.50%
BCOC | BCEC
Organization and Business
Percentage of ownership interest of BCEC		29.90%

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ORGANIZATION AND BUSINESS:

9 Months Ended

Sep. 30, 2012

ORGANIZATION AND BUSINESS:

ORGANIZATION AND BUSINESS:

1. ORGANIZATION AND BUSINESS:

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

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

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

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

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

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

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

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

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

The Company is engaged primarily in acquiring, developing, exploiting and producing oil and gas properties. As of September 30, 2012, the Company’s assets and operations are concentrated primarily in the Wattenberg field and North Park Basin in the Rocky Mountains and in southern Arkansas.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Sep. 30, 2012	Dec. 31, 2011
CONSOLIDATED BALANCE SHEETS
Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized	25,000,000	25,000,000
Preferred stock, shares outstanding	0	0
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized	225,000,000	225,000,000
Common stock, shares issued	40,057,248	39,477,584
Common stock, shares outstanding	40,057,248	39,477,584

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IMPAIRMENT OF PROVED PROPERTIES:

9 Months Ended

Sep. 30, 2012

IMPAIRMENT OF PROVED PROPERTIES:

IMPAIRMENT OF PROVED PROPERTIES:

11. IMPAIRMENT OF PROVED PROPERTIES:

The Company recorded $1.6 million of proved property impairments on the Company’s legacy California assets and $0.3 million of proved property impairment in one non-core field in Southern Arkansas for the nine months ended September 30, 2012.  The impairments of the Company’s legacy assets in California were related to anticipated sales proceeds that were lower than the net book value of the properties as of September 30, 2012 and the impairment of the non-core field in Southern Arkansas was related to a the well repair that did not restore the well to its previous production levels.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2012
Document and Entity Information
Entity Registrant Name	Bonanza Creek Energy, Inc.
Entity Central Index Key	0001509589
Document Type	10-Q
Document Period End Date	Sep. 30, 2012
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	40,057,248
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3

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SUBSEQUENT EVENTS:

9 Months Ended

Sep. 30, 2012

SUBSEQUENT EVENTS:

SUBSEQUENT EVENTS:

12.  SUBSEQUENT EVENTS:

On October 11, 2012, the Company sold Liberty Energy, LLC, which owned a 50% non-operated interest in the Sargent field in California, for approximately $3.2 million. During the quarter ended September 30, 2012, an impairment charge in the amount of $460,000 was recorded to write the field down to the sales price and no gain or loss was recorded on this transaction.

On October 30, 2012, the lenders under the Company’s senior secured revolving credit agreement redetermined the Company’s borrowing base resulting in an increase of the borrowing base to $325 million which excludes the value of the oil and gas properties held for sale.

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
NET REVENUES
Oil and gas sales	$ 58,327,823	$ 25,915,330	$ 157,613,348	$ 70,608,993
OPERATING EXPENSES:
Lease operating	8,444,403	4,686,328	22,506,131	12,040,775
Severance and ad valorem taxes	3,021,860	1,342,646	9,387,094	3,778,946
Exploration	6,359,222	18,608	9,563,876	566,210
Depreciation, depletion and amortization	17,715,763	6,329,995	41,751,296	18,472,491
Impairment of proved properties	268,500	623,039	268,500	623,039
General and administrative (including $1,445,910, $132,720, $2,912,248, and $132,720, respectively, of stock compensation)	9,335,266	4,179,301	22,410,369	9,115,956
Total operating expenses	45,145,014	17,179,917	105,887,266	44,597,417
INCOME FROM OPERATIONS	13,182,809	8,735,413	51,726,082	26,011,576
OTHER INCOME (EXPENSE):
Other loss	(90,640)	(3,526)	(82,930)	(100,805)
Interest expense	(1,125,634)	(1,121,907)	(2,341,843)	(2,686,684)
Unrealized (loss) gain in fair value of commodity derivatives	(9,007,034)	8,268,367	2,985,356	7,095,912
Loss in fair value of commodity derivatives	(92,812)	(519,287)	(1,173,619)	(2,353,187)
Total other income (expense)	(10,316,120)	6,623,647	(613,036)	1,955,236
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES	2,866,689	15,359,060	51,113,046	27,966,812
Income tax expense	(1,222,450)	(8,527,646)	(19,797,360)	(13,176,124)
INCOME FROM CONTINUING OPERATIONS	1,644,239	6,831,414	31,315,686	14,790,688
DISCONTINUED OPERATIONS (Note 3)
Loss from operations associated with oil and gas properties held for sale	(1,410,595)	(3,754,649)	(791,394)	(3,635,226)
Gain on sale of oil and gas properties	4,279,998		4,279,998
Income tax (expense) benefit	(1,092,755)	1,756,587	(1,331,147)	1,712,555
Income (loss) associated with oil and gas properties held for sale	1,776,648	(1,998,062)	2,157,457	(1,922,671)
NET INCOME	$ 3,420,887	$ 4,833,352	$ 33,473,143	$ 12,868,017
BASIC AND DILUTED INCOME PER SHARE
Income from continuing operations (in dollars per share)	$ 0.04	$ 0.23	$ 0.79	$ 0.51
Income (loss) from discontinued operations (in dollars per share)	$ 0.05	$ (0.06)	$ 0.06	$ (0.07)
Net income per common share (in dollars per share)	$ 0.09	$ 0.17	$ 0.85	$ 0.44
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK-BASIC (in shares)	39,477,101	29,122,521	39,476,133	29,122,521
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK-DILUTED (in shares)	39,477,101	29,122,521	39,476,133	29,122,521

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SENIOR SECURED REVOLVING CREDIT FACILITY:

9 Months Ended

Sep. 30, 2012

SENIOR SECURED REVOLVING CREDIT FACILITY:

SENIOR SECURED REVOLVING CREDIT FACILITY:

6. SENIOR SECURED REVOLVING CREDIT FACILITY:

Senior Secured Revolving Credit Facility—On May 8, 2012, the Company amended its senior secured revolving Credit Agreement, (the “Revolver”) dated March 29, 2011, with a syndication of banks, including KeyBank National Association as the administrative agent and issuing lender, which provides for borrowings of up to $600 million. The Revolver provides for interest rates plus an applicable margin to be determined based on the London Interbank Offered Rate (LIBOR) or a bank base rate (“Base Rate”), at the Company’s election. LIBOR borrowings bear interest at LIBOR plus 1.75% to 2.75% depending on the utilization level, and the Base Rate borrowings bear interest at the “Bank Prime Rate,” as defined plus .75% to 1.75%.

The Revolver had a $245 million borrowing base as of September 30, 2012 and is subject to semi-annual re-determinations in April and October of each year. The letter of credit that was issued to the Colorado State Board of Land Commissioners reduced the borrowing base by approximately $48 million.  The Revolver provides for commitment fees ranging from 0.375% to 0.50%, depending on utilization, and restricts, among other items, the payment of dividends, certain additional indebtedness, sale of assets, loans, and certain investments and mergers. The Revolver also contains certain financial covenants, which require the maintenance of a minimum current ratio and a minimum debt coverage ratio, as defined. The Company was in compliance with these covenants as of September 30, 2012. The Revolver is collateralized by substantially all the Company’s assets and matures on September 15, 2016.

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ACCOUNTS PAYABLE AND ACCRUED EXPENSES:

9 Months Ended

Sep. 30, 2012

ACCOUNTS PAYABLE AND ACCRUED EXPENSES:

ACCOUNTS PAYABLE AND ACCRUED EXPENSES:

5. ACCOUNTS PAYABLE AND ACCRUED EXPENSES:

Accounts payable and accrued expenses contain the following:

	2012		2011
Drilling and completion costs	$	51,010,731	$	14,153,449
Accounts payable trade	267,213		4,976,979
Ad valorem taxes	190,627		1,781,021
Accrued general and administrative cost	5,039,156		1,713,708
Accrued initial public offering expenses	—		1,258,791
Lease operating expense	2,510,000		2,128,470
Accrued reclamation cost	400,000		400,000
Accrued interest	634,162		17,965
Accrued oil and gas hedging	314,537		353,897
Production taxes and other	2,627,474		284,046
	$	62,993,900	$	27,068,326

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FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION: (Tables)

9 Months Ended

Sep. 30, 2012

FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION:

Schedule of financial assets and liabilities at fair value on recurring basis

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2012 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3
Commodity derivative assets	$	—	$	825,074	$	2,439,922
Commodity derivative liabilities	$	—	$	6,159,571	$	—

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2011 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3
Commodity derivative assets	$	—	$	1,094,055	$	881,822
Commodity derivative liabilities	$	—	$	6,740,213	$	1,115,595

Schedule of activity for commodity derivatives measured at fair value using Level 3 inputs

The following table reflects the activity for the commodity derivatives measured at fair value using Level 3 inputs during the period from January 1, 2012 through September 30, 2012:

	Derivative Asset			Derivative Liability
Beginning net asset (liability) balance	$	881,822		$	(1,115,595	)
Net increase in fair value	(654,780		)	4,978,506
Net realized (gain) on settlement	(231,511		)	(233,412		)
New derivatives	411,178			(1,596,286		)
Transfers in (out) of Level 3	—			—
Ending net asset (liability) balance	$	406,709		$	2,033,213

Schedule of derivative commodity contracts

Contract Term	Notional Volume	Average Floor		Average Ceiling		Average Fixed Price
October 1 - December 31, 2012	77,956 Bbl./Month	$	90.00	$	106.05	—
January 1 - December 31, 2013	44,218 Bbl./Month	$	91.61	$	106.46	—
October 1 - December 31, 2012	49,400 Bbl./Month	—		—		$	88.78
January 1 - December 31, 2013	76,285 Bbl./Month	—		—		$	88.08
October 1 - December 31, 2012	323,103 MMBTU/Month	—		—		$	3.33
January 1 - October 31, 2013	15,481 MMBTU/Month	—		—		$	6.40

Schedule of derivative positions reported on consolidated balance sheet

Derivatives	Balance Sheet Location	Fair Value
Asset
Commodity derivatives	Current derivative assets	$	2,714,219
Commodity derivatives	Long-term derivative assets	550,777
Liability
Commodity derivatives	Current derivative liability	(5,339,006		)
Commodity derivatives	Long-term derivative liability	(820,565		)
Total		$	(2,894,575	)

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BASIS OF PRESENTATION: (Policies)

9 Months Ended

Sep. 30, 2012

BASIS OF PRESENTATION:

Principles of Consolidation

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

Oil and Gas Producing Activities

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

Depletion, Depreciation and Amortization

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

Impairment of Oil and Gas Properties

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

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STOCKHOLDERS' EQUITY:

9 Months Ended

Sep. 30, 2012

STOCKHOLDERS' EQUITY:

STOCKHOLDERS' EQUITY:

9. STOCKHOLDERS’ EQUITY:

BCEI Management Incentive Plan—On December 23, 2010, the Company established the Management Incentive Plan (the “Plan” or “MIP”) for the benefit of certain employees, officers and other individuals performing services for the Company. 10,000 shares of Class B common stock were available under the Plan and these shares were converted into 437,787 shares of restricted common stock upon completion of our initial public offering. The conversion rate was determined based on a formula factoring in the rate of return to the common stockholders. The 437,787 shares of common stock that were granted to employees were valued at $17.00 per share on the grant date and vest over a three year period. Non-cash compensation expense of approximately $1,822,000 was recorded during the nine months ended September 30, 2012 and there was approximately $5,372,000 of unrecognized compensation costs related to the unvested restricted common stock granted under the Plan. That cost is expected to be recognized over a period of 2.25 years.

BCEC Management Incentive Plan—As of September 30, 2012, 73,197 shares of BCEI common stock remain held in trust and designated for holders of BCEC’s Class B units. When and if such shares are issued, they will be valued based on the market price of the Company’s common stock on the grant date.

BCEI Long Term Incentive Plan—On June 14, 2012, the Company granted 540,000 shares of restricted common stock under its 2011 Long Term Incentive Plan (the “LTIP”) to officers and certain key employees. For accounting purposes, these shares were valued at $15.38, the closing price of our common stock on the grant date. These shares will vest annually in one-third increments over approximately 2.7 years and will be fully vested in February of 2015. On August 15, 2012, the Company granted an additional 25,000 shares of restricted stock under the LTIP to a newly hired key employee. For accounting purposes, these shares were valued at $19.03, the closing price our common stock on the grant date. These shares will vest annually in one-third increments over 3 years and will be fully vested in August of 2015. On August 3, 2012, the Company granted an aggregate of 16,626 shares of common stock under the LTIP to the four independent members of our Board of Directors in 2011 for their 2011-2012 service.  For accounting purposes, these shares were valued at $18.04, the closing price our common stock on the grant date and vested upon grant and non-cash compensation expense of approximately $300,000 was recorded during the period from April 1, 2011 through June 30, 2012.  On August 3, 2012, the Company granted an aggregate of 16,908 shares of common stock under the LTIP to the four independent members of our Board of Directors in 2012 for their 2012-2013 service.  For accounting purposes, these shares were valued at $18.04, the closing price our common stock on the grant date and will vest immediately prior to the Company’s 2013 Annual Meeting. Non-cash compensation expense of approximately $73,000 was recorded during the quarter ended September 30, 2012.

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COMMITMENTS AND CONTINGENT LIABILITIES:

9 Months Ended

Sep. 30, 2012

COMMITMENTS AND CONTINGENT LIABILITIES:

COMMITMENTS AND CONTINGENT LIABILITIES:

7. COMMITMENTS AND CONTINGENT LIABILITIES:

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

	Office Leases		Wattenberg FieldLease Acquisition		Line of Credit		Total
2012	$	297,265	$	—	—		$	297,265
2013	1,098,709		11,999,987		—		13,098,696
2014	1,085,740		11,999,987		—		13,085,727
2015	1,111,256		11,999,987		—		13,111,243
2016 and thereafter	2,235,743		11,999,987		122,300,000		136,535,730
	$	5,828,713	$	47,999,948	$	122,300,000	$	176,128,661

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

Legal Proceedings—From time to time, the Company is subject to legal proceedings and claims that arise in the ordinary course of business. Like other gas and oil producers and marketers, the Company’s operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. As of the date of this filing, there are no material pending or overtly threatened legal actions against the Company of which it is aware.

In June 2011, Frank H. Bennett, a co-manager of BCOC, BCEC’s predecessor, and former chairman of BCEC, made a demand against Michael R. Starzer, our President and Chief Executive Officer, focusing on Mr. Starzer’s handling of the operation, accounting and finances of BCOC and BCEC primarily during the 2005-2006 time period. Mr. Bennett’s demands do not allege any wrongdoing by or claims against Bonanza Creek Energy, Inc. This matter was sent to arbitration in July 2011.

In July 2011, the Company’s board of directors formed a Special Litigation Committee comprised of three non-executive directors to conduct an investigation of the allegations. The Special Litigation Committee retained outside independent advisors and conducted an in-depth investigation. The Special Litigation Committee concluded that neither it nor its legal or financial advisors had found any evidence to support any of Mr. Bennett’s allegations. The Company’s Board of Directors concluded that the allegations against Mr. Starzer are unsubstantiated and lack merit. However, there can be no assurance as to the ultimate outcome of the arbitration proceedings. An arbitration hearing commenced in July 2012 and it is not clear when a final decision will be rendered regarding the allegations or any potential recovery of legal fees. Mr. Starzer plans to continue to vigorously defend against Mr. Bennett’s claims. During the period from January 1, 2012 through September 30, 2012, the Company incurred approximately $2.5 million for the advancement of legal fees related to Mr. Bennett’s claims.

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FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION:

9 Months Ended

Sep. 30, 2012

FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION:

FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION:

8. FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION:

The Company follows FASB ASC 820, Fair Value Measurements and Disclosures, which defines fair value, establishes a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. The statement establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

Level 1:Quoted prices are available in active markets for identical assets or liabilities;

Level 2:Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; or

Level 3:Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

Financial assets and liabilities to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2012 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3
Commodity derivative assets	$	—	$	825,074	$	2,439,922
Commodity derivative liabilities	$	—	$	6,159,571	$	—

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2011 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3
Commodity derivative assets	$	—	$	1,094,055	$	881,822
Commodity derivative liabilities	$	—	$	6,740,213	$	1,115,595

Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.  All valuations were compared against counterparty statements to verify the reasonableness of the estimate.  The Company’s commodity swaps are validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and are designated as Level 2 within the valuation hierarchy. The Company’s collars, which are designated as Level 3 within the valuation hierarchy, are not validated by observable transactions with respect to volatility. The counterparties in all of the commodity derivative financial instruments are lenders on the Company’s senior secured revolving credit facility.

The following table reflects the activity for the commodity derivatives measured at fair value using Level 3 inputs during the period from January 1, 2012 through September 30, 2012:

	Derivative Asset			Derivative Liability
Beginning net asset (liability) balance	$	881,822		$	(1,115,595	)
Net increase in fair value	(654,780		)	4,978,506
Net realized (gain) on settlement	(231,511		)	(233,412		)
New derivatives	411,178			(1,596,286		)
Transfers in (out) of Level 3	—			—
Ending net asset (liability) balance	$	406,709		$	2,033,213

As of September 30, 2012, the Company’s derivative commodity contracts:

Contract Term	Notional Volume	Average Floor		Average Ceiling		Average Fixed Price
October 1 - December 31, 2012	77,956 Bbl./Month	$	90.00	$	106.05	—
January 1 - December 31, 2013	44,218 Bbl./Month	$	91.61	$	106.46	—
October 1 - December 31, 2012	49,400 Bbl./Month	—		—		$	88.78
January 1 - December 31, 2013	76,285 Bbl./Month	—		—		$	88.08
October 1 - December 31, 2012	323,103 MMBTU/Month	—		—		$	3.33
January 1 - October 31, 2013	15,481 MMBTU/Month	—		—		$	6.40

The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of September 30, 2012:

Derivatives	Balance Sheet Location	Fair Value
Asset
Commodity derivatives	Current derivative assets	$	2,714,219
Commodity derivatives	Long-term derivative assets	550,777
Liability
Commodity derivatives	Current derivative liability	(5,339,006		)
Commodity derivatives	Long-term derivative liability	(820,565		)
Total		$	(2,894,575	)

Realized gains and losses on commodity derivatives and the unrealized gains or losses are recorded in other income (expense).

Asset Retirement Obligation—Upon completion of wells and natural gas plants, the Company records an asset retirement obligation at fair value using Level 3 assumptions.

Proved Oil and Gas Properties—Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs exceed the sum of the undiscounted cash flows. The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts selected by the Company’s management. The calculation of the discount rate is a significant management estimate based on the best information available and estimated to be 10 percent for the nine months ended September 30, 2011. Management believes that the discount rate is representative of current market conditions and reflects the following factors: estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on New York Mercantile Exchange (“NYMEX”) strip pricing, adjusted for basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates.

As a result of the impairment discussed in Note 11—Impairment of Proved Properties, the proved oil and gas properties measured at fair value within the accompanying balance sheets as of September 30, 2012 and 2011 were $4.6 million and $6.3 million, respectively.

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INCOME TAXES:

9 Months Ended

Sep. 30, 2012

INCOME TAXES:

INCOME TAXES:

10. INCOME TAXES:

The Company uses the asset and liability method of accounting for deferred income taxes.  Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities.  Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time.

The deferred income tax liability for an oil and gas exploration company is dependent on many variables such as estimating the economic lives of depleting oil and gas reserves and commodity prices.  Accordingly, the liability is subject to continual recalculation, revision of the numerous estimates required, and may change significantly in the event of such things as major acquisitions, divestitures, product price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws.

The Company follows the provisions of FASB ASC 740, Accounting for Uncertainty in Income Taxes. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The Company files income tax returns in the U.S. federal jurisdiction and various states. The Company has not taken any uncertain tax positions.

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FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION: (Details 4) (USD $)	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2012
Derivatives measured at fair value
Estimated discount rate to measure fair value of proved oil and gas properties (as a percent)	10.00%
Impairment of proved properties	$ 6,300,000	$ 4,600,000
Fair Value
Derivatives measured at fair value
Total		(2,894,575)
Commodity derivatives | Fair Value | Current derivative assets
Derivatives measured at fair value
Derivative asset		2,714,219
Commodity derivatives | Fair Value | Long term derivative assets
Derivatives measured at fair value
Derivative asset		550,777
Commodity derivatives | Fair Value | Current derivative liability
Derivatives measured at fair value
Derivative liability		(5,339,006)
Commodity derivatives | Fair Value | Long term derivative liability
Derivatives measured at fair value
Derivative liability		$ (820,565)

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ACCOUNTS PAYABLE AND ACCRUED EXPENSES: (Tables)

9 Months Ended

Sep. 30, 2012

ACCOUNTS PAYABLE AND ACCRUED EXPENSES:

Schedule of accounts payable and accrued expenses

	2012		2011
Drilling and completion costs	$	51,010,731	$	14,153,449
Accounts payable trade	267,213		4,976,979
Ad valorem taxes	190,627		1,781,021
Accrued general and administrative cost	5,039,156		1,713,708
Accrued initial public offering expenses	—		1,258,791
Lease operating expense	2,510,000		2,128,470
Accrued reclamation cost	400,000		400,000
Accrued interest	634,162		17,965
Accrued oil and gas hedging	314,537		353,897
Production taxes and other	2,627,474		284,046
	$	62,993,900	$	27,068,326

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ACQUISTIONS AND DIVESTITURES: (Details 2) (USD $)	0 Months Ended	3 Months Ended		9 Months Ended
	Aug. 31, 2012	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2011
ACQUISTIONS AND DIVESTITURES:
Period within which sale of asset takes place to classify it as held for sale				1 year
ACQUISTIONS AND DIVESTITURES
Sale value of oil and gas properties				$ 5,212,000
Gain on sale of oil and gas properties		4,279,998		4,279,998
Oil and gas properties, successful efforts method;
Proved properties		718,962,011		718,962,011		547,878,188
Unproved properties		72,928,364		72,928,364		15,848,703
OIL AND GAS PROPERTIES-using the successful efforts method of accounting		861,710,126		861,710,126		587,510,033
Less accumulated depletion and depreciation		(66,199,440)		(66,199,440)		(26,759,043)
OIL AND GAS PROPERTIES-net, using the successful efforts method of accounting		795,510,686		795,510,686		560,750,990
NET REVENUES
Oil and gas sales		58,327,823	25,915,330	157,613,348	70,608,993
OPERATING EXPENSES:
Lease operating		8,444,403	4,686,328	22,506,131	12,040,775
Severance and ad valorem taxes		3,021,860	1,342,646	9,387,094	3,778,946
Exploration		6,359,222	18,608	9,563,876	566,210
Depreciation, depletion and amortization				43,900,774	21,083,067
Impairment of proved properties		268,500	623,039	268,500	623,039
TOTAL COSTS AND EXPENSES		45,145,014	17,179,917	105,887,266	44,597,417
INCOME FROM OPERATIONS		13,182,809	8,735,413	51,726,082	26,011,576
Oil and gas properties in California
ACQUISTIONS AND DIVESTITURES
Sale value of oil and gas properties	5,100,000
Gain on sale of oil and gas properties	4,300,000
Oil and gas properties, successful efforts method;
Proved properties		7,799,582		7,799,582		13,060,597
Unproved properties		32,013		32,013		32,013
Wells in progress		30,629		30,629		167,198
OIL AND GAS PROPERTIES-using the successful efforts method of accounting		7,862,224		7,862,224		13,259,808
Less accumulated depletion and depreciation		(2,823,942)		(2,823,942)		(3,364,300)
OIL AND GAS PROPERTIES-net, using the successful efforts method of accounting		5,038,282		5,038,282		9,895,508
ASSET RETIREMENT OBLIGATIONS		769,700		769,700		975,562
NET REVENUES
Oil and gas sales		1,274,906	1,458,198	5,000,665	4,927,493
OPERATING EXPENSES:
Lease operating		451,795	795,428	1,853,085	2,419,715
Severance and ad valorem taxes		8,809	(1,000)	124,298	81,449
Exploration		6,219	400	17,008	6,995
Depreciation, depletion and amortization		570,488	974,035	2,149,478	2,610,576
Impairment of proved properties		1,648,190	3,443,984	1,648,190	3,443,984
TOTAL COSTS AND EXPENSES		2,685,501	5,212,847	5,792,059	8,562,719
INCOME FROM OPERATIONS		$ (1,410,595)	$ (3,754,649)	$ (791,394)	$ (3,635,226)

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CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2012	Sep. 30, 2011
CONSOLIDATED STATEMENTS OF OPERATIONS
General and administrative, stock compensation	$ 1,445,910	$ 132,720	$ 2,912,248	$ 132,720

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RECENT ACCOUNTING PRONOUNCEMENTS:

9 Months Ended

Sep. 30, 2012

RECENT ACCOUNTING PRONOUNCEMENTS:

RECENT ACCOUNTING PRONOUNCEMENTS:

4. RECENT ACCOUNTING PRONOUNCEMENTS:

In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). The objective of ASU 2011-11 is to require an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. ASU 2011-11 is effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively. The adoption of this standard is not expected to have an impact on the Company’s consolidated financial statements.

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

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ACCOUNTS PAYABLE AND ACCRUED EXPENSES: (Details) (USD $)	Sep. 30, 2012	Dec. 31, 2011
Accounts payable and accrued expenses contain the following:
Drilling and completion costs	$ 51,010,731	$ 14,153,449
Accounts payable trade	267,213	4,976,979
Ad valorem taxes	190,627	1,781,021
Accrued general and administrative cost	5,039,156	1,713,708
Accrued initial public offering expenses		1,258,791
Lease operating expense	2,510,000	2,128,470
Accrued reclamation cost	400,000	400,000
Accrued interest	634,162	17,965
Accrued oil and gas hedging	314,537	353,897
Production taxes and other	2,627,474	284,046
Total accounts payable and accrued expenses	$ 62,993,900	$ 27,068,326

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ACQUISTIONS AND DIVESTITURES: (Tables)

9 Months Ended

Sep. 30, 2012

ACQUISTIONS AND DIVESTITURES:

Schedule of carrying amounts of the major classes of assets and liabilities related to the operation of the remaining properties that are held for sale

	As of September 30, 2012			As of December 31, 2011
PROPERTY AND EQUIPMENT:
Oil and gas properties, successful efforts method:
Proved properties	$	7,799,582		$	13,060,597
Unproved properties	32,013			32,013
Wells in progress	30,629			167,198
Total property and equipment	7,862,224			13,259,808
Less accumulated depletion and depreciation	(2,823,942		)	(3,364,300		)
Net property and equipment	$	5,038,282		$	9,895,508
ASSET RETIREMENT OBLIGATIONS	$	769,700		$	975,562

Schedule of total revenues and costs and expenses, and the income associated with the operation of the oil and gas properties held for sale

	Three Months Ended September 30			Three Months Ended September 30			Nine MonthsEnded September 30			Nine Months Ended September 30
	2012			2011			2012			2011
NET REVENUES:
Oil and gas sales	$	1,274,906		$	1,458,198		$	5,000,665		$	4,927,493
OPERATING EXPENSES:
Lease operating	451,795			795,428			1,853,085			2,419,715
Severance and ad valorem taxes	8,809			(1,000		)	124,298			81,449
Exploration	6,219			400			17,008			6,995
Depreciation, depletion and amortization	570,488			974,035			2,149,478			2,610,576
Impairment of proved properties	1,648,190			3,443,984			1,648,190			3,443,984
TOTAL COSTS AND EXPENSES	2,685,501			5,212,847			5,792,059			8,562,719
LOSS FROM OPERATIONS ASSOCIATED WITH OIL AND GAS PROPERTIES HELD FOR SALE	$	(1,410,595	)	$	(3,754,649	)	$	(791,394	)	$	(3,635,226	)