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 June 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. 40,011,894 shares of common stock were outstanding as of June 30, 2012.

PART I - FINANCIAL INFORMATION

Item 1.   Financial Statements.

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(unaudited)

	June 30, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,605,378		$	2,089,674
Accounts receivable:
Oil and gas sales	24,346,613			17,850,719
Other	12,012,855			5,696,825
Prepaid expenses and other	1,899,507			1,868,016
Inventory of oilfield equipment	2,609,464			3,324,368
Derivative asset	7,369,944			1,297,403
Total current assets	50,843,761			32,127,005
OIL AND GAS PROPERTIES—using the successful efforts method of accounting:
Proved properties	647,233,892			547,878,188
Unproved properties	15,851,016			15,848,703
Wells in progress	68,775,281			23,783,142
	731,860,189			587,510,033
Less: accumulated depreciation, depletion and amortization	(49,330,212		)	(26,759,043		)
	682,529,977			560,750,990
NATURAL GAS PLANT	61,707,490			56,910,232
Less: accumulated depreciation	(2,287,223		)	(1,286,129		)
	59,420,267			55,624,103
PROPERTY AND EQUIPMENT	3,452,170			1,983,037
Less: accumulated depreciation	(405,824		)	(128,731		)
	3,046,346			1,854,306
Oil and gas properties held for sale less accumulated depreciation, depletion, and amortization — Note 3	8,788,960			9,895,508
LONG-TERM DERIVATIVE ASSET	2,075,644			678,474
OTHER ASSETS, net	3,345,531			3,418,626
TOTAL ASSETS	$	810,050,486		$	664,349,012
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	64,431,194		$	27,068,326
Oil and gas revenue distribution payable	8,485,093			6,185,983
Derivative liability	2,536,623			5,276,633
Total current liabilities	75,452,910			38,530,942
LONG-TERM LIABILITIES:
Bank revolving credit	62,600,000			6,600,000
Ad valorem taxes	6,354,355			3,014,023
Derivative liability	796,506			2,579,175
Deferred income taxes, net	98,416,935			79,603,633
Asset retirement obligations	6,929,670			6,039,723
TOTAL LIABILITIES	250,550,376			136,367,496
COMMITMENTS AND CONTINGENCIES (Note 7)
STOCKHOLDERS’ EQUITY:
Preferred stock, $.001 par value, 25,000,000 shares authorized, 0 outstanding	—			—
Common stock, $.001 par value, 225,000,000 shares authorized, 40,011,894 and 39,477,584 issued and outstanding, respectively	40,012			39,478
Additional paid-in capital	516,878,387			515,412,583
Retained earnings	42,581,711			12,529,455
Total stockholders’ equity	559,500,110			527,981,516
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	810,050,486		$	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  June 30						Six Months Ended June 30,
	2012			2011			2012			2011
NET REVENUES
Oil and gas sales	$	51,455,094		$	24,151,668		$	99,285,525		$	44,693,663
OPERATING EXPENSES:
Lease operating	6,954,397			3,679,573			14,061,728			7,354,447
Severance and ad valorem taxes	2,769,425			1,396,514			6,365,234			2,436,300
Exploration	2,014,531			22,798			3,204,654			547,602
Depreciation, depletion and amortization	13,034,490			6,624,007			24,035,533			12,142,496
General and administrative (including $795,774, $60,000, $1,466,338, and $60,000,  respectively, of stock compensation)	7,110,385			2,698,101			13,075,103			4,936,655
Total operating expenses	31,883,228			14,420,993			60,742,252			27,417,500
INCOME FROM OPERATIONS	19,571,866			9,730,675			38,543,273			17,276,163
OTHER INCOME (EXPENSE):
Other income (loss)	45,437			(165,225		)	7,710			(97,279		)
Interest expense	(654,693		)	(852,005		)	(1,216,209		)	(1,564,777		)
Unrealized (loss) in fair value of commodity derivatives	15,368,221			4,282,091			11,992,390			(1,172,455		)
Realized (loss) in fair value of commodity derivatives	130,332			(1,057,980		)	(1,080,807		)	(1,833,900		)
Total other income (loss)	14,889,297			2,206,881			9,703,084			(4,668,411		)
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES	34,461,163			11,937,556			48,246,357			12,607,752
Deferred income taxes (Note 10)	(13,267,610		)	(4,400,505		)	(18,574,910		)	(4,648,478		)
INCOME FROM CONTINUING OPERATIONS	$	21,193,553		$	7,537,051		29,671,447			$	7,959,274
DISCONTINUED OPERATIONS (Note 3)
Income from operations associated with oil and gas properties held for sale	508,211			270,699			619,201			119,423
Deferred income taxes benefit	(195,661		)	(100,005		)	(238,392		)	(44,032		)
Income associated with oil and gas properties held for sale	312,550			170,694			380,809			75,391
NET INCOME	$	21,506,103		$	7,707,745		$	30,052,256		$	8,034,665
BASIC AND DILUTED INCOME PER SHARE
Income from continuing operations	$	0.53		$	0.25		$	0.75		$	0.28
Income (loss) from discontinued operations	$	0.01		$	0.01		$	0.01		$	—
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—BASIC AND DILUTED	39,474,011			29,122,521			39,475,797			29,122,521

See accompanying notes to these consolidated financial statements.

3

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	30,052,256		$	8,034,665
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	25,614,523			13,779,037
Deferred income taxes	18,813,302			4,692,510
Non-cash stock compensation	1,466,338			60,000
Exploration	1,575,494			—
Amortization of deferred financing costs	464,377			447,197
Valuation (increase) decrease in commodity derivatives	(11,992,390		)	1,172,455
Other	3,334			(39,868		)
(Increase) decrease in operating assets:
Accounts receivable	(12,811,924		)	(4,219,346		)
Prepaid expenses and other assets	(31,491		)	(135,423		)
(Decrease) increase in operating liabilities:
Accounts payable and accrued liabilities	3,381,752			(1,884,356		)
Settlement of asset retirement obligations	(146,125		)	(80,435		)
Net cash provided by operating activities	56,389,446			21,826,436
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of oil and gas properties	(553,731		)	(777,621		)
Exploration and development of oil and gas properties	(102,945,699		)	(46,265,409		)
Natural gas plant capital expenditures	(6,510,563		)	(11,141,877		)
Proceeds from note receivable	—			986,906
Decrease in restricted cash	232,580			—
Additions to property and equipment—non oil and gas	(1,469,133		)	(214,021		)
Net cash used in investing activities	(111,246,546		)	(57,412,022		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in bank revolving credit	56,000,000			103,200,000
Payment on bank revolving credit	—			(65,800,000		)
Deferred financing costs	(627,196		)	(1,814,414		)
Net cash provided by financing activities	55,372,804			35,585,586
NET INCREASE IN CASH AND CASH EQUIVALENTS	515,704			—
CASH AND CASH EQUIVALENTS:
Beginning of period	2,089,674			—
End of period	$	2,605,378		$	—
SUPPLEMENTAL CASH FLOW DISCLOSURE:
Cash paid for interest	$	512,000		$	943,555
Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition	$	39,577,503		$	4,694,941

See accompanying notes to these consolidated financial statements.

4

Bonanza Creek Energy, Inc.

Notes to the Consolidated Financial Statements as of June 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 June 30, 2012, the Company’s assets and operations are concentrated primarily in southern Arkansas and in the Wattenberg field and North Park Basin in the Rocky Mountains.

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.

5

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, Bonanza Creek Energy Midstream, LLC and Liberty Energy Company, 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.

3. DIVESTITURES:

During June of 2012, the Company began marketing, with an intent to sell, all of its oil and gas properties in California.  In accordance with ASC Topic 360, 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 although the Company has not yet reached any definitive agreement with a counter party to sell the properties.  The carrying amounts of the major classes of assets and liabilities related to the operation of these properties that are held for sale as of June 30, 2012 and December 31, 2011 are presented below:

	As of June 30, 2012			As of December 31, 2011
PROPERTY AND EQUIPMENT:
Oil and gas properties, successful efforts method:
Proved properties	$	13,061,985		$	13,060,597
Unproved properties	32,013			32,013
Wells in progress	581,387			167,198
Total property and equipment	13,675,385			13,259,808
Less accumulated depletion and depreciation	(4,886,425		)	(3,364,300		)
Net property and equipment	$	8,788,960		$	9,895,508
ASSET RETIREMENT OBLIGATIONS	$	1,014,974		$	975,562

6

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 six month periods ended June 30, 2012 and 2011 are presented below.

	Three Months Ended June 30		Three Months Ended June 30		Six MonthsEnded June 30		Six Months Ended June 30
	2012		2011		2012		2011
NET REVENUES:
Oil and gas sales	$	2,013,861	$	1,798,673	$	3,725,759	$	3,469,295
Total revenue	2,013,861		1,798,673		3,725,759		3,469,295
OPERATING EXPENSES:
Lease operating	733,547		685,137		1,401,290		1,624,287
Severance and ad valorem taxes	19,863		69,316		115,489		82,449
Exploration	187		5,935		10,789		6,595
Depreciation, depletion and amortization	752,053		767,586		1,578,990		1,636,541
TOTAL COSTS AND EXPENSES	1,505,650		1,527,974		3,106,558		3,349,872
INCOME FROM OPERATIONS ASSOCIATED WITH OIL AND GAS PROPERTIES HELD FOR SALE	$	508,211	$	270,699	$	619,201	$	119,423

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	$	53,730,952	$	14,153,449
Accounts payable trade	2,528,046		4,976,979
Ad valorem taxes	190,627		1,781,021
Accrued general and administrative cost	2,494,509		1,713,708
Accrued initial public offering expenses	—		1,258,791
Lease operating expense	2,361,200		2,128,470
Accrued reclamation cost	400,000		400,000
Accrued interest	257,797		17,965
Accrued oil and gas hedging	186,973		353,897
Production taxes and other	2,281,090		284,046
	$	64,431,194	$	27,068,326

7

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 June 30, 2012 and is subject to semi-annual re-determinations in April and October of each year. 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 June 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		Line of Credit		Total
2012	$	537,233	$	—	$	537,233
2013	1,098,709		—		1,098,709
2014	1,085,740		—		1,085,740
2015	1,111,256		—		1,111,256
2016 and thereafter	2,235,743		62,600,000		64,835,743
	$	6,068,681	$	62,600,000	$	68,668,681

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—The Company may from time to time be involved in various legal actions arising in the normal course of business. During the second quarter of 2011, its Board of Directors formed a Special Litigation Committee comprised of three non-executive directors to investigate the merits of a demand for arbitration against its current President and Chief Executive Officer from the former Chairman of BCEC related to the management of BCOC and BCEC primarily during the 2005-2006 time period. These demands do not allege any wrongdoing by or claims against the Company. The Special Litigation Committee retained outside independent advisors to conduct the investigation and concluded that the allegations lack merit.  An arbitration hearing commenced in July 2012 and it is not clear when a final decision will be rendered.  Mr. Starzer plans to continue to vigorously defend against Mr. Bennett’s claims.  During the period from January 1, 2012 through June 30, 2012 the Company incurred approximately $1.2 million related to Mr. Bennett’s claims.

8

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.

ASC 820 requires 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 June 30, 2012 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3
Commodity derivative assets	$	—	$	2,526,789	$	6,918,799
Commodity derivative liabilities	$	—	$	3,333,129	$	—

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 June 30, 2012:

	Derivative Asset			Derivative Liability
Beginning net asset (liability) balance	$	881,822		$	(1,115,595	)
Net increase in fair value	330,830			8,014,163
Net realized (gain) on settlement	(181,946		)	(121,686		)
New derivatives	411,178			(1,299,967		)
Transfers in (out) of Level 3	—			—
Ending net asset (liability) balance	$	1,441,884		$	5,476,915

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

Contract Term	Notional Volume	Average Floor		Average Ceiling		Average Fixed Price
July 1 - December 31, 2012	77,956 Bbl./Month	$	90.00	$	106.05	—
January 1 - December 31, 2013	34,218 Bbl./Month	$	92.10	$	108.91	—
July 1 - December 31, 2012	29,563 Bbl./Month	—		—		$	85.22
January 1 - December 31, 2013	16,285 Bbl./Month	—		—		$	81.72
July 1 - December 31, 2012	16,625 MMBTU/Month	—		—		$	6.75
January 1 - October 31, 2013	15,481 MMBTU/Month	—		—		$	6.40

9

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

Derivatives	Balance Sheet Location	Fair Value
Asset
Commodity derivatives	Current derivative assets	$	7,369,944
Commodity derivatives	Long-term derivative assets	2,075,644
Liability
Commodity derivatives	Current derivative liability	(2,536,623		)
Commodity derivatives	Long-term derivative liability	(796,506		)
Total		$	6,112,459

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.

9. STOCKHOLDERS’ EQUITY:

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 its 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 $1,223,000 was recorded during the six months ended June 30, 2012 and there was approximately $6,019,000 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 2.5 years.

BCEC Management Incentive Plan—As of June 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.

On June 14, 2012, the Company granted 540,000 shares of restricted common stock under its 2011 Long Term Incentive Plan to officers and certain employees.  For accounting purposes, these shares were valued at $15.38, the closing price of its 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.

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. SUBSEQUENT EVENTS:

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 for approximately $60,000,000.  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.

10

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

11

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.

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 southern Arkansas (Mid-Continent region) and the Wattenberg Field and North Park Basins in Colorado (Rocky Mountain 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 recently amended $298 million capital program for 2012, we are increasingly focused on exploiting our inventory of high-return locations.  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.

Second Quarter 2012 Highlights:

For the second quarter 2012,

·Total production was 793 MBoe (8,717 Boe/d average daily production), a 150% increase over the second quarter 2011 and 26% over the first quarter 2012;

·Total revenue was $51.5 million, a 113% increase over the second quarter 2011 and 8% over the first quarter 2012; and

·Net income was $21.2 million, or $0.53 per diluted share.

Results for Continuing Operations

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

Revenues

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

	Three Months Ended June 30,
	2012		2011		Change			Percent Change
	(In thousands, except percentages)
Revenues:
Crude oil sales	$	44,000	$	18,263	$	25,737		141	%
Natural gas sales	4,296		2,755		1,541			56	%
Natural gas liquids sales	3,151		2,987		164			5	%
CO2 sales	8		146		(138		)	(94	)%
Product revenues	$	51,455	$	24,151	$	27,304		113	%

	Three Months Ended June 30,
	2012	2011	Change	Percent Change
Sales volumes:
Crude oil (MBbls)	491.8	188.7	303.1	161	%
Natural gas (MMcf)	1,406.6	544.6	862.0	158	%
Natural gas liquids (MBbls)	67.0	37.2	29.8	80	%
Crude oil equivalent (MBoe)(1)	793.2	316.7	476.5	150	%

(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 June 30,
	2012		2011		Change			Percent Change
Average Sales Prices (before hedging)(1):
Crude oil (per Bbl)	$	89.47	$	96.78	$	(7.31	)	(8	)%
Natural gas (per Mcf)	3.05		5.06		(2.01		)	(40	)%
Natural gas liquids (per Bbl)	47.03		80.30		(33.27		)	(41	)%
Crude oil equivalent (per Boe)(2)	64.86		75.80		(10.94		)	(14	)%

	Three Months Ended June 30,
	2012		2011		Change			Percent Change
Average Sales Prices (after hedging)(1):
Crude oil (per Bbl)	$	89.26	$	90.36	$	(1.10	)	(1	)%
Natural gas (per Mcf)	3.22		5.34		(2.12		)	(40	)%
Natural gas liquids (per Bbl)	47.03		80.30		(33.27		)	(41	)%
Crude oil equivalent (per Boe)(2)	65.02		72.46		(7.44		)	(10	)%

(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 113%, to $51.5 million for the three months ended June 30, 2012 compared to $24.2 million for the three months ended June 30, 2011.  Oil, natural gas, and natural gas liquids production increased 161%, 158%, and 80%, respectively, during the three months ended June 30, 2012, as compared to the three months ended June 30, 2011.  During the period from June 30, 2011 through June 30, 2012, we drilled and completed 97 gross (91.9 net) wells in the Rockies and 49 gross (42.5 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 $149.6 million expended during the six months ended June 30, 2012.  Oil prices decreased from an average of $96.78 in 2011 to a per barrel rate of $89.47 in the comparable three month period that ended June 30, 2012.  Increased oil volumes of 161% accounted for $25.7 million of the total $27.3 million increase in revenues for the Company for the three month period ended June 30, 2012 compared to the same period in 2011.  Natural gas volumes increased by 158% in 2012, but were offset by a sales price decline of 40% from $5.06 per Mcf to $3.05 per Mcf for these three month periods. Natural gas liquids volumes increased by 80% in 2012, but were offset by a sales price decline of 41% from $80.30 per barrel to $47.03 per barrel for these three 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 three months ended June 30, 2012 was approximately 62%, 30% and 8%, 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	$	6,954	$	3,680	$	3,274	89	%
Severance and ad valorem taxes	2,769		1,396		1,373		98	%
General and administrative	7,110		2,698		4,412		164	%
Depreciation, depletion and amortization	13,035		6,624		6,411		97	%
Exploration	2,015		23		1,992		8,661	%
Operating expenses	$	31,883	$	14,421	$	17,462	121	%

	Three Months Ended June 30,
	2012		2011		Change			Percent Change
Selected Costs ($ per Boe):
Lease operating	$	8.77	$	11.62	$	(2.85	)	(25	)%
Severance and ad valorem taxes	3.49		4.41		(0.92		)	(21	)%
General and administrative	8.96		8.52		0.44			5	%
Depreciation, depletion and amortization	16.43		20.92		(4.49		)	(21	)%
Exploration	2.54		0.07		2.47			3,529	%
Operating expenses	$	40.19	$	45.54	$	(5.35	)	(12	)%

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Lease Operating Expense.  Our lease operating expenses increased $3.3 million, or 89%, to $7.0 million for the three months ended June 30, 2012 from $3.7 million for the three months ended June 30, 2011 and decreased on an equivalent basis from $11.62 per Boe to $8.77 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, but not operational during the three months ended June 30, 2011.  Gas plant operating expense, which is a component of lease operating expense, increased $0.6 million, or 36%, to $2.1 million for the three month period ended June 30, 2012 from $1.5 million for the three month period ended June 30, 2011.  Significant increases in gas plant operating expenses period over period were for compression and rental equipment and repairs and maintenance which were $0.3 million and $0.2 million, respectively.  During the three months ended June 30, 2012, well servicing, rental equipment, and other expenses were $1.8 million, $0.2 million, and $0.2 million higher, respectively, than the three months ended June 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 June 30, 2011 through June 30, 2012.

Severance and ad valorem taxes.Our severance and ad valorem taxes increased $1.4 million, or 98%, to $2.8 million for the three months ended June 30, 2012 from $1.4 million for the three months ended June 30, 2011.  The increase was primarily related to a 150% increase in production volumes partially offset by a 14% decrease in realized prices per Boe during the three months ended June 30, 2012 as compared to the three months ended June 30, 2011.  The increase in severance and ad valorem taxes for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011 was related to oil severance taxes and ad valorem taxes that were $0.4 million and $1.0 million, respectively, higher than the comparable period in the previous year.

Exploration costs.  Our exploration expense increased $2.0 million, or 8,661%, to $2.0 million in the three months ended June 30, 2012 from $23 thousand in the three months ended June 30, 2011.  During the three months ended June 30, 2012, a seismic acquisition project in the North Park Basin of Colorado was reprocessed which resulted in charges of approximately $0.5 million. One exploratory location where surface casing had been set and minimal work performed was also charged to exploration expense because the work had been performed during 2010 and management had no current plans to complete a well on this location.  This resulted in a $1.5 million non-cash charge to our statement of operations during the three months ended June 30, 2012.

Depletion, depreciation and amortization.Our depletion, depreciation and amortization expense increased $6.4 million, or 97%, to $13.0 million for the three months ended June 30, 2012 from $6.6 million for the three months ended June 30, 2011.  This increase was the result of a 150% increase in production period over period.  Our depreciation, depletion and amortization expense per Boe produced decreased $4.49, or 21% to $16.43 for the three months ended June 30, 2012 as compared to $20.92 for the three months ended June 30, 2011.  This decrease to depreciation, depletion and amortization expense per Boe resulted from additions to the proved developed reserve base from accretive drilling during the period from July 1, 2011 through June 30, 2012.

General and administrative. Our general and administrative expense increased $4.4 million, or 164%, to $7.1 million for the three months ended June 30, 2012 from $2.7 million for the period ended June 30, 2011. During the three months ended June 30, 2012, wages, benefits and employee placement fees were $2.5 million higher than the three month period ended June 30, 2011 due to our headcount increasing by approximately 50 employees, or 69% period over period, 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 June 30, 2012, legal fees were $0.9 million higher, software maintenance was $0.1 million higher and non-cash stock compensation charges for officers and certain employees were $0.7 million higher than the three month period ended June 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 decreased $0.2 million, or 23%, to $0.7 million for the three months ended June 30, 2012 from $0.9 million for the three months ended June 30, 2011.  The decrease resulted from a decrease in the average debt outstanding for the three months ended June 30, 2012 compared to the three months ended June 30, 2011.  Average debt outstanding for the three months ended June 30, 2012 was $44.7 million as compared to $74.0 million for the three month ended June 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 $1.1 million for the three months ended June 30, 2011 to a gain of $0.1 million for the three months ended June 30, 2012.  The change from a realized loss to a realized gain period over period was primarily related to commodity prices that were 14% lower during the three month period ended June 30, 2012.  Hedging gains for the month of June were $0.8 million as the NYMEX sweet

14

crude oil price averaged $82.41 during June of 2012 as compared to our oil hedges which had an average floor of $88.61 per barrel during June of 2012.

Income tax expense.  Our estimate for federal and state income taxes for the three months ended June 30, 2012 was $13.3 million from continuing operations as compared to $4.4 million for the three months ended June 30, 2011.  We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation.  All income taxes for the periods ended June 30, 2012 and 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.

Six Months Ended June 30, 2012 Compared To Six Months Ended June 30, 2011

Revenues

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

	Six Months Ended June 30,
	2012		2011		Change			Percent Change
	(In thousands, except percentages)
Revenues:
Crude oil sales	$	84,124	$	33,169	$	50,955		154	%
Natural gas sales	7,569		5,681		1,888			33	%
Natural gas liquids sales	7,559		5,678		1,881			33	%
CO2 sales	33		166		(133		)	(80	)%
Product revenues	$	99,285	$	44,694	$	54,591		122	%

	Six Months Ended June 30,
	2012	2011	Change	Percent Change
Sales volumes:
Crude oil (MBbls)	895.6	357.4	538.2	151	%
Natural gas (MMcf)	2,352.1	1,123.1	1,229.0	109	%
Natural gas liquids (MBbls)	135.8	83.4	52.4	63	%
Crude oil equivalent (MBoe)(1)	1,423.4	628.0	795.4	127	%

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

	Six Months Ended June 30,
	2012		2011		Change			Percent Change
Average Sales Prices (before hedging)(1):
Crude oil (per Bbl)	$	93.93	$	92.81	$	1.12		1	%
Natural gas (per Mcf)	3.22		5.06		(1.84		)	(36	)%
Natural gas liquids (per Bbl)	55.66		68.08		(12.42		)	(18	)%
Crude oil equivalent (per Boe)(2)	69.73		70.90		(1.17		)	(2	)%

	Six Months Ended June 30,
	2012		2011		Change			Percent Change
Average Sales Prices (after hedging)(1):
Crude oil (per Bbl)	$	92.23	$	86.78	$	5.45		6	%
Natural gas (per Mcf)	3.40		5.34		(1.94		)	(36	)%
Natural gas liquids (per Bbl)	55.66		68.08		(12.42		)	(18	)%
Crude oil equivalent (per Boe)(2)	68.97		67.98		0.99			1	%

(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.

15

Revenues increased by 122%, to $99.3 million for the six months ended June 30, 2012 compared to $44.7 million for the six months ended June 30, 2011.  Oil, natural gas, and natural gas liquids production increased 151%, 109%, and 63%, respectively, during the six months ended June 30, 2012, as compared to the six months ended June 30, 2011.  During the period from June 30, 2011 through June 30, 2012, we drilled and completed 97 gross (91.9 net) wells in the Rockies and 49 gross (42.5 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 $149.8 million expended during the six months ended June 30, 2012.  Oil prices increased from an average of $92.81 in 2011 to a per barrel rate of $93.93 in the comparable six month period that ended June 30, 2012.  The combination of increased oil volumes and prices accounted for $51.0 million of the total $54.6 million increase in revenues for the Company for the six month period ended June 30, 2012 compared to the same period in 2011.  Natural gas volumes increased by 109% in 2012, but were offset by a sales price decline of 36% from $5.06 per Mcf to $3.22 per Mcf for these six month periods.  Natural gas liquid volumes increased by 63% in 2012, but were offset by a salesprices decline of 18% from $68.08 per Bbl to $55.66 per Bbl for these six 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 six months ended June 30, 2012 was approximately 63%, 27% and 10%, 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	$	14,062	$	7,354	$	6,708	91	%
Severance and ad valorem taxes	6,365		2,436		3,929		161	%
General and administrative	13,075		4,937		8,138		165	%
Depreciation, depletion and amortization	24,036		12,142		11,894		96	%
Exploration	3,205		548		2,657		485	%
Operating expenses	$	60,743	$	27,417	$	33,326	122	%

	Six Months Ended June 30,
	2012		2011		Change			Percent Change
Selected Costs ($ per Boe):
Lease operating	$	9.88	$	11.71	$	(1.83	)	(16	)%
Severance and ad valorem taxes	4.47		3.88		0.59			15	%
General and administrative	9.19		7.86		1.33			17	%
Depreciation, depletion and amortization	16.89		19.33		(2.44		)	(13	)%
Exploration	2.25		0.87		1.38			159	%
Operating expenses	$	42.68	$	43.65	$	(0.97	)	(2	)%

Lease Operating Expense.  Our lease operating expenses increased $6.7 million, or 91%, to $14.1 million for the six months ended June 30, 2012 from $7.4 million for the six months ended June 30, 2011 and decreased on an equivalent basis from $11.71 per Boe to $9.88 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, but not operational during the six months ended June 30, 2011.  Gas plant operating expense, which is a component of lease operating expense, increased $1.4 million, or 55%, to $4.0 million for the six month period ended June 30, 2012 from $2.6 million for the six month period ended June 30, 2011.  Significant increases in gas plant operating expenses period over period were for compression and rental equipment, repairs and maintenance, and utilities and electrical which were $0.8 million, $0.4 million, and $0.3 million, respectively.  During the six months ended June 30, 2012, well servicing, rental equipment, pumping and gauging, and other expenses were $2.9 million, $0.4 million, $0.3 million and $0.3 million higher, respectively, than the six months ended June 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 June 30, 2011 through June 30, 2012.

Severance and ad valorem taxes.Our severance and ad valorem taxes increased $4.0 million, or 161%, to $6.4 million for the six months ended June 30, 2012 from $2.4 million for the six months ended June 30, 2011.  The increase was primarily related to a 127% increase in production volumes partially offset and a 2% decrease in realized prices per Boe during the six months ended June 30, 2012 as compared to the six months ended June 30, 2011.  The increase in severance and ad valorem taxes on a Boe basis for the six months ended June 30, 2012 as compared to the six months ended June 30, 2011 was related to oil severance taxes and ad valorem taxes that were $2.5 million and $1.2 million, respectively, higher than the comparable period in the previous year.

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Exploration costs.  Our exploration expense increased $2.7 million, or 485%, to $3.2 million in the six months ended June 30, 2012 from $0.5 million in the six months ended June 30, 2011.  During the six months ended June 30, 2012, a seismic acquisition project was conducted in the North Park Basin of Colorado to assist the scientific staff in identifying the appropriate drill locations and plans for future development.  This survey was reprocessed during the second quarter which resulted in additional charges of approximately $0.5 million. In addition to the seismic survey, one exploratory location where surface casing had been set and minimal work performed was charged to exploration expense because the work had been performed during 2010 and management had no current plans to complete a well on this location.  This resulted in a $1.5 million non-cash charge to our statement of operations during the six months ended June 30, 2012. During the six months ended June 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.

Depletion, depreciation and amortization.Our depletion, depreciation and amortization expense increased $11.9 million, or 96%, to $24.0 million for the six months ended June 30, 2012 from $12.1 million for the six months ended June 30, 2011.  This increase was the result of a 127% increase in production period over period.  Our depreciation, depletion and amortization expense per Boe produced decreased $2.44, or 13% to $16.89 for the six months ended June 30, 2012 as compared to $19.33 for the six months ended June 30, 2011.  This decrease to depreciation, depletion and amortization expense per Boe resulted from additions to the proved developed reserve base from accretive drilling during the period from July 1, 2011 through June 30, 2012.

General and administrative. Our general and administrative expense increased $8.1 million, or 165%, to $13.1 million for the six months ended June 30, 2012 from $5.0 million for the six months ended June 30, 2011. During the six months ended June 30, 2012, wages, benefits and employee placement fees were $4.9 million higher than the six month period ended June 30, 2011 due to our headcount increasing by approximately 50 employees, or 74% period over period, as the result of our accelerated drilling program and the addition of accounting, legal and IT positions that were previously outsourced. During the six months ended June 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 six months ended June 30, 2012, legal fees were $1.0 million higher, franchise taxes were $0.3 million higher and non-cash stock compensation charges for officers and certain employees were $1.4 million higher than the six month period ended June 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 decreased $0.4 million, or 22%, to $1.2 million for the six months ended June 30, 2012 from $1.6 million for the six months ended June 30, 2011.  The decrease resulted from a decrease in the average debt outstanding for the six months ended June 30, 2012 compared to the six months ended June 30, 2011.  Average debt outstanding for the six months ended June 30, 2012 was $29.9 million as compared to $67.7 million for the six months ended June 30, 2011.

Realized loss on settled commodity derivatives.  Realized losses on oil and gas hedging activities decreased by $0.7 million from a loss of $1.8 million for the six months ended June 30, 2011 to a loss of $1.1 million for the six months ended June 30, 2012.  The decrease in the realized loss period over period was primarily related to hedging gains for the month of June which were $0.8 million as the NYMEX sweet crude oil price averaged $82.41 per barrel during June of 2012 as compared to our oil hedges which had an average floor of $88.61 per barrel during June of 2012.

Income tax expense.  Our estimate for federal and state income taxes for continuing operations for the six months ended June 30, 2012 was $18.6 million as compared to $4.6 million for the six months ended June 30, 2011.  We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation.  All income taxes for the periods ended June 30, 2012 and 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.

The operating results before income taxes for our California properties for the three month period ended June 30, 2012 were net revenues, operating expenses, and income from discontinued operations of $2.0 million, $1.5 million and $0.5 million, respectively, as compared to net revenues, operating expenses, and income from discontinued operations of $1.8 million, $1.5 million, and $0.3 million for the three month period ended June 30, 2011.  Sales volumes for the three month periods ended June 30, 2012 and 2011 were 20.6 MBbls and 16.3 MBbls, respectively.

The operating results before income taxes for our California properties for the six month period ended June 30, 2012 were net revenues, operating expenses, and income from discontinued operations of $3.7 million, $3.1 million and $0.6 million, respectively, as compared to net

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revenues, operating expenses, and income from discontinued operations of $3.5 million, $3.4 million, and $0.1 million for the six month period ended June 30, 2011.  Sales volumes for the six month periods ended June 30, 2012 and 2011 were 36.6 MBbls and 34.7 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 June 30, 2012, we had $62.6 million outstanding and $182.4 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 for approximately $60,000,000.  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.

	Six Months Ended June 30,
	2012			2011
	(In thousands)
Net cash provided by operating activities	$	56,389		$	21,826
Net cash provided by (used in) investing activities	(111,247		)	(57,412		)
Net cash provided by financing activities	55,373			35,586
Cash and cash equivalents	2,605			—
Acquisitions of oil and gas properties	554			778
Exploration and development of oil and gas properties and investment in gas processing facility	109,456			57,407

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 $56.4 million for the six months ended June 30, 2012, compared to $21.8 million provided by operating activities for the six months ended June 30, 2011.  The increase in operating activities results primarily

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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 six months ended June 30, 2012 was $9.6 million compared to $6.3 million that was utilized by changes in working capital for the comparable period during 2011.  Decreases in working capital of $9.6 million for the six months ended June 30, 2012 is comprised of increases in accounts receivable of $12.8 million offset by an increase in accounts payable and accrued liabilities (exclusive of capital accruals) of $3.4 million.  Decreases in working capital of $6.3 million for the six month period ended June 30, 2011 is comprised of increases in accounts receivable of $4.2 million and decreases in accounts payable and accrued liabilities (exclusive of capital accruals) of $1.9 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 six months ended June 30, 2012 was $111.2 million, compared to $57.4 million used in investing activities for the six months ended June 30, 2011.  For the six months ended June 30, 2012, cash used for the development of oil and natural gas properties was $109.5 million including $6.5 million for a natural gas plant.  In the Wattenberg field during the six months ended June 30, 2012, we drilled and completed 54 gross (50.5 net) wells of which 13 gross (12.2 net) were horizontal Niobrara wells.  In Southern Arkansas, we drilled and completed drilled 24 gross (19.5 net) vertical wells.

Cash provided by financing activities

Net cash provided by financing activities for the six months ended June 30, 2012 was $55.4 million related to net borrowings on our line of credit in the amount of $56.0 million offset by deferred financing costs of $0.6 million.  Net cash provided by financing activities for the six months ended June 30, 2011 was $35.6 million related to net borrowings on our line of credit in the amount of $37.4 million offset by deferred financing costs of $1.8 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.

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 six month periods ended June 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 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 June 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	467,736	$	90.00	$	106.05	$	3,245,731
	Swap	177,380	85.22		85.22		(165,762		)
2013	Collar	410,616	92.10		108.91		3,673,068
	Swap	195,417	81.72		81.72		(1,461,368		)
Gas
2012	Swap	99,748	6.75		6.75		377,896
2013	Swap	154,806	6.40		6.40		442,894
							$	6,112,459

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 June 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

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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 June 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 June 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. The arbitration proceedings commenced in July 2012 and it is not clear when a final decision will be rendered.  Mr. Starzer plans to continue to vigorously defend against Mr. Bennett’s claims.

See Part I, Item 1, Note 7 to our unaudited condensed consolidated financial statements entitled “Commitment and Contingent Liabilities,” which is incorporated herein by reference.

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 June 30, 2012, there has been no material change to such risk factors.

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

None.

Item 3.    Defaults Upon Senior Securities.

None.

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Item 4.    Mine Safety Disclosures.

Not applicable.

Item 5.    Other Information.

None.

Item 6.    Exhibits.

Exhibit No.	Description of Exhibit
10.1	Resignation, Consent and Appointment Agreement and Amendment Agreement, date as of April 6, 2012, by and among BNP Paribas, in its capacity as Administrative Agent and Issuing Lender, and the other parties thereto (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the three months ended March 31, 2012 filed on May 11, 2012)
10.2	Amendment No. 3 & Agreement, dated as of May 8, 2012, to the Credit Agreement among Bonanza Creek Energy, Inc., KeyBank National Association, as Administrative Agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the three months ended March 31, 2012 filed on May 11, 2012)
10.3	From of Restricted Stock Agreement (Employee) under the 2011 Bonanza Creek Energy, Inc. Long Term Incentive Plan
10.4	Form of Restricted Stock Agreement (Director) under the 2011 Bonanza Creek Energy, Inc. Long Term Incentive Plan
10.5	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
31.1	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)
31.2	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)
32.1	Certification of the Chief 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 Chief 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 June 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:	August 13, 2012	By:	/s/ MICHAEL R. STARZER
		Michael R. Starzer
		President and Chief Executive Officer
		(principal executive officer)
		By:	/s/ JAMES R. CASPERSON
		James R. Casperson
		Executive Vice President and Chief Financial Officer
		(principal financial officer)

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EX-10.3

Exhibit 10.3

RESTRICTED STOCK AGREEMENT

[EMPLOYEE FORM]

THIS RESTRICTED STOCK AGREEMENT (this “Agreement”), is entered into as of the Grant Date (as defined below), by and between Grantee (as defined below) and Bonanza Creek Energy, Inc., a Delaware corporation (the “Company”).

WHEREAS, the Company maintains the Bonanza Creek Energy, Inc. 2011 Long Term Incentive Plan (the “Plan”), which is incorporated into and forms a part of this Agreement, and Grantee has been selected by the board of directors of the Company (the “Board”) or the compensation committee of the Board (the “Committee”) to receive a restricted stock award (the “Award”) under the Plan as set forth in this Agreement;

NOW, THEREFORE, IT IS AGREED, by and between the Company and Grantee, as follows:

1.  Definitions.  The following terms used in this Agreement shall have the meanings set forth in this paragraph 1:

(a)“Cause” shall have the meaning set forth in any applicable agreement between the Company and Grantee regarding Grantee’s Service with the Company and, if “Cause” is not so defined, shall mean any of the following: (i) Grantee has failed or refused to substantially perform Grantee’s duties, responsibilities, or authorities (other than any such refusal or failure resulting from Grantee’s becoming Disabled); (ii) any commission by or indictment of Grantee of a felony or other crime of moral turpitude; (iii) Grantee has engaged in material misconduct in the course and scope of Grantee’s Service with the Company, including, but not limited to, gross incompetence, disloyalty, disorderly conduct, insubordination, harassment of other employees or third parties, chronic abuse of alcohol or unprescribed controlled substances, improper disclosure of confidential information, chronic and unexcused absenteeism, improper appropriation of a corporate opportunity or any other material violation of the Company’s personnel policies, rules or codes of conduct or any fiduciary duty owed to the Company or its Affiliates, or any applicable law or regulation to which the Company or its Affiliates are subject; (iv) Grantee has committed any act of fraud, embezzlement, theft, dishonesty, misrepresentation or falsification of records; or (v) Grantee has engaged in any act or omission that is likely to materially damage the Company’s business, including, without limitation, damages to the Company’s reputation.

(b)“Covered Shares” means shares of the Company’s Common Stock granted under this Agreement and are subject to the terms of this Agreement and the Plan.  The number of “Covered Shares” granted to you under this Agreement is the number of shares of the Company’s Common Stock specified in the grant notice that you received from the Company on or about [DATE].

1

(c)“Date of Termination” means the date on which Grantee’s Service with the Company or an Affiliate terminates for any reason, provided, that a Date of Termination shall not be deemed to occur by reason of a Grantee’s transfer of Service between the Company and an Affiliate; further provided that a Grantee’s Service shall not be considered terminated while Grantee is on a leave of absence from the Company or an Affiliate approved by the Company or such Affiliate.

(d)“Designated Beneficiary” means the beneficiary or beneficiaries designated by Grantee in a writing filed with the Company in the form attached hereto as Exhibit A.

(e)“Disabled” as it relates to Grantee shall have the meaning of “Disabled” or such similar term set forth in any applicable agreement between the Company and Grantee regarding Grantee’s Service with the Company and, if “Disabled” or such similar term is not so defined, shall mean when (i) Grantee receives disability benefits under either social security or the Company’s long-term disability plan, if any, or (ii) the Company, upon the written report of a qualified physician designated by the Company’s insurers, shall have determined (after a complete physical examination of Grantee at any time after Grantee has been absent from the Company for 90 or more consecutive calendar days) that Grantee has become physically and/or mentally incapable of performing Grantee’s essential job functions with or without reasonable accommodation as required by law due to injury, illness, or other incapacity (physical or mental).

(f)“Good Reason” shall have the meaning set forth in any applicable agreement between the Company and Grantee regarding Grantee’s Service with the Company and, if “Good Reason” is not so defined, shall exist in the event any of the following actions are taken without Grantee’s consent: (i) Grantee’s authority with the Company is, or Grantee’s duties or responsibilities based on Grantee’s position with the Company or any employment agreement or arrangement between Grantee and the Company are, materially diminished relative to Grantee’s authority, duties and responsibilities as in effect immediately prior to such change; provided, however, that in no event shall removal of Grantee from the position of manager, director or officer of any direct or indirect Affiliate of the Company in connection with any corporate restructuring constitute Good Reason; (ii) a material diminution in Grantee’s base salary or retainer compensation as in effect immediately prior to such diminution; provided, that, an across-the-board reduction in the base compensation and benefits of all Service Providers of the Company by the same percentage amount (or under the same terms and conditions) as part of a general base compensation reduction and/or benefit reduction shall not constitute such a qualifying material diminution; (iii) a material relocation of Grantee’s primary work location more than 75 miles away from the then-current primary work location; or (iv) any material breach by the Company of any provision of this Agreement or any employment agreement or arrangement between Grantee and the Company.

2

(g)“Grantee” means you, the employee of the Company specified in the grant notice that you received from the Company on or about [DATE].

(h)“Grant Date” means [DATE].

(i)“Installment” means a portion of Covered Shares.

Capitalized terms used herein without definition have the meanings ascribed to such terms in the Plan.  Except where the context clearly implies or indicates the contrary, a word, term, or phrase used in the Plan is similarly used in this Agreement.

2.  Award.  Grantee is hereby granted the number of Covered Shares set forth in paragraph 1.

3.  Delivery of Covered Shares.  Covered Shares shall be registered in book entry form with the Company’s transfer agent.  During the applicable Restricted Period, Covered Shares may carry the following legend or any other legend the Board or the Committee (if so authorized) deems applicable:

“THESE SECURITIES ARE SUBJECT TO THE VESTING RESTRICTIONS AND OTHER PROVISIONS OF THE BONANZA CREEK ENERGY, INC. 2011 LONG TERM INCENTIVE PLAN AND THE RESTRICTED STOCK AGREEMENT BETWEEN BONANZA CREEK ENERGY, INC. AND THE HOLDER OF THESE SECURITIES.”

4.  Restricted Period.  The “Restricted Period” for each Installment of Covered Shares shall begin on the Grant Date and end on the date scheduled below applicable to such Installment: (1)

INSTALLMENT	RESTRICTED PERIOD WILL END ON:
[FRACTION OF COVERED SHARES] of the Covered Shares	[DATE]

[ADD ADDITIONAL ROWS AS APPROPRIATE]

Covered Shares may not be sold, assigned, transferred, pledged or otherwise encumbered prior to the expiration of the Restricted Period applicable to such Installment of Covered Shares.

5.  Transfer and Forfeiture of Shares.  Grantee shall forfeit any Installment of Covered Shares for which the Restricted Period has not expired as of a Date of Termination.  If a Date of Termination does not occur during a Restricted Period with respect to an Installment of the Covered Shares, then, at the end of the Restricted Period that is applicable for such Installment, Grantee shall become vested in those Covered Shares, and such Installment shall be transferred to Grantee free of all restrictions otherwise imposed by this Agreement.

(1)  Vesting terms to be confirmed for each grant.

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Notwithstanding the foregoing, in the event that Grantee’s Date of Termination occurs within six (6) months of a Change in Control on account of (a) Grantee’s termination of Service by the Company without Cause or (b) Grantee’s resignation from the Company for Good Reason, then any Installment of Covered Shares for which the Restricted Period has not expired as of such Date of Termination shall become vested as of such Date of Termination and such Installment shall be transferred to Grantee free of all restrictions otherwise imposed by this Agreement.

6.  Withholding.  The grant and vesting of shares of Stock under this Agreement are subject to withholding of all applicable taxes.  At the election of Grantee, and subject to such rules and limitations as may be established by the Board from time to time, such withholding obligations may be satisfied through the surrender of shares of Stock (a) which Grantee already owns, or (b) to which Grantee is otherwise entitled under the Plan; provided, however, that shares described in this clause (b) may be used to satisfy not more than the Company’s minimum statutory withholding obligation (based on minimum statutory withholding rates for federal and state tax purposes, including payroll taxes, that are applicable to such taxable income).

7.  Dividends.  Grantee shall not be prevented from receiving dividends and distributions paid on the Covered Shares merely because those shares are subject to the restrictions imposed by this Agreement and the Plan; provided, however that no dividends or distributions shall be payable to or for the benefit of Grantee with respect to record dates for such dividends or distributions for any Covered Shares occurring on or after the date, if any, on which Grantee has forfeited those shares.

8.  Voting.  Grantee shall not be prevented from voting the Covered Shares merely because those shares are subject to the restrictions imposed by this Agreement and the Plan; provided, however, that Grantee shall not be entitled to vote Covered Shares with respect to record dates for any Covered Shares occurring on or after the date, if any, on which Grantee has forfeited those shares.

9.  Heirs and Successors.  This Agreement shall be binding upon, and inure to the benefit of, the Company and its successors and assigns, and upon any person acquiring, whether by merger, consolidation, purchase of assets or otherwise, all or substantially all of the Company’s assets and business.  If any rights of Grantee or benefits distributable to Grantee under this Agreement have not been exercised or distributed, respectively, at the time of Grantee’s death, such rights shall be exercisable by the Designated Beneficiary, and such benefits shall be distributed to the Designated Beneficiary, in accordance with the provisions of this Agreement and the Plan.  If a deceased Grantee fails to designate a beneficiary, or if the Designated Beneficiary does not survive Grantee, any rights that would have been exercisable by Grantee and any benefits distributable to Grantee shall be exercised by or distributed to the legal representative of the estate of Grantee.  If a deceased Grantee designates a beneficiary and the Designated Beneficiary survives Grantee but dies before the Designated Beneficiary’s exercise of all rights under this Agreement or before the complete distribution of benefits to the Designated Beneficiary under this Agreement, then any rights that would have been exercisable by the Designated Beneficiary shall be exercised by the legal representative of the estate of the Designated Beneficiary, and any benefits distributable to the Designated Beneficiary shall be distributed to the legal representative of the estate of the Designated Beneficiary.

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10.  Administration.  The authority to manage and control the operation and administration of this Agreement shall be vested in the Board, and the Board shall have all powers with respect to this Agreement as it has with respect to the Plan.  Any interpretation of the Agreement by the Board and any decision made by it with respect to the Agreement is final and binding on all persons.

11.  Plan Governs.  Notwithstanding anything in this Agreement to the contrary, the terms of this Agreement shall be subject to the terms of the Plan, a copy of which may be obtained by Grantee from the office of the Secretary of the Company; and this Agreement is subject to all interpretations, amendments, rules and regulations promulgated by the Board from time to time pursuant to the Plan.

12.  Fractional Shares.  In lieu of issuing a fraction of a share of Stock resulting from an adjustment of the Award pursuant to Section 17.4 of the Plan or otherwise, the Company will be entitled to pay to Grantee an amount equal to the fair market value of such fractional share.

13.  Not An Employment Contract.  The Award will not confer on Grantee any right with respect to continuance of employment or other service with the Company or any Subsidiary, nor will it interfere in any way with any right the Company or any Subsidiary would otherwise have to terminate or modify the terms of such Grantee’s Service at any time.

14.  Notices.  Any written notices provided for in this Agreement or the Plan shall be in writing and shall be deemed sufficiently given if either hand delivered or if sent by fax or overnight courier, or by postage paid first class mail.  Notices sent by mail shall be deemed received three business days after mailing but in no event later than the date of actual receipt.  Notices shall be directed, if to Grantee, at Grantee’s address indicated by the Company’s records, or if to the Company, at the Company’s principal executive office.

15.  Amendment.  This Agreement may be amended in accordance with the provisions of the Plan, and may otherwise be amended by written agreement of Grantee and the Company without the consent of any other person.

16.  Section 83(b) Election.  With the prior consent of the President, Chief Executive Officer, Chief Financial Officer or General Counsel of the Company, Grantee may, within 30 days of the Grant Date, file an election under section 83(b) of the Code with the Internal Revenue Service with respect to the Covered Shares (a “Section 83(b) Election”).  Within five business days of filing a Section 83(b) Election, Grantee shall provide a copy of such completed election form to the Company at the following address: 410 17th Street, Suite 1400, Denver, CO 80202, Attention: General Counsel.  Grantee acknowledges that any Section 83(b) Election is Grantee’s sole responsibility, and additionally acknowledges that the Company has hereby advised Grantee to consult with a financial or tax advisor of Grantee’s own choosing with regard to the federal and state tax considerations resulting from the Award and/or the effect of filing a Section 83(b) Election.  The Company is unable to give Grantee any advice or counseling with respect to federal and state tax matters.

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EX-10.4

Exhibit 10.4

RESTRICTED STOCK AGREEMENT

[DIRECTOR FORM]

THIS RESTRICTED STOCK AGREEMENT (this “Agreement”), is entered into as of the Grant Date (as defined below), by and between Grantee (as defined below) and Bonanza Creek Energy, Inc., a Delaware corporation (the “Company”).

WHEREAS, the Company maintains the Bonanza Creek Energy, Inc. 2011 Long Term Incentive Plan (the “Plan”), which is incorporated into and forms a part of this Agreement, and Grantee has been selected by the board of directors of the Company (the “Board”) or the compensation committee of the Board (the “Committee”) to receive a restricted stock award (the “Award”) under the Plan as set forth in this Agreement;

NOW, THEREFORE, IT IS AGREED, by and between the Company and Grantee, as follows:

1.  Definitions.  The following terms used in this Agreement shall have the meanings set forth in this paragraph 1:

(a)“Cause” shall have the meaning set forth in any applicable agreement between the Company and Grantee regarding Grantee’s Service with the Company and, if “Cause” is not so defined, shall mean any of the following: (i) Grantee has failed or refused to substantially perform Grantee’s duties, responsibilities, or authorities (other than any such refusal or failure resulting from Grantee’s becoming Disabled); (ii) any commission by or indictment of Grantee of a felony or other crime of moral turpitude; (iii) Grantee has engaged in material misconduct in the course and scope of Grantee’s Service with the Company, including, but not limited to, gross incompetence, disloyalty, disorderly conduct, insubordination, harassment of other employees or third parties, chronic abuse of alcohol or unprescribed controlled substances, improper disclosure of confidential information, chronic and unexcused absenteeism, improper appropriation of a corporate opportunity or any other material violation of the Company’s personnel policies, rules or codes of conduct or any fiduciary duty owed to the Company or its Affiliates, or any applicable law or regulation to which the Company or its Affiliates are subject; (iv) Grantee has committed any act of fraud, embezzlement, theft, dishonesty, misrepresentation or falsification of records; or (v) Grantee has engaged in any act or omission that is likely to materially damage the Company’s business, including, without limitation, damages to the Company’s reputation.

(b)“Covered Shares” means shares of the Company’s Common Stock granted under this Agreement and are subject to the terms of this Agreement and the Plan.  The number of “Covered Shares” granted to you under this Agreement is the number of shares of the Company’s Common Stock specified in the grant notice that you received from the Company on or about [DATE].

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(c)“Date of Termination” means the date on which Grantee’s Service with the Company or an Affiliate terminates for any reason, provided, that a Date of Termination shall not be deemed to occur by reason of a Grantee’s transfer of Service between the Company and an Affiliate; further provided that a Grantee’s Service shall not be considered terminated while Grantee is on a leave of absence from the Company or an Affiliate approved by the Company or such Affiliate.

(d)“Designated Beneficiary” means the beneficiary or beneficiaries designated by Grantee in a writing filed with the Company in the form attached hereto as Exhibit A.

(e)“Disabled” as it relates to Grantee shall have the meaning of “Disabled” or such similar term set forth in any applicable agreement between the Company and Grantee regarding Grantee’s Service with the Company and, if “Disabled” or such similar term is not so defined, shall mean when (i) Grantee receives disability benefits under either social security or the Company’s long-term disability plan, if any, or (ii) the Company, upon the written report of a qualified physician designated by the Company’s insurers, shall have determined (after a complete physical examination of Grantee at any time after Grantee has been absent from the Company for 90 or more consecutive calendar days) that Grantee has become physically and/or mentally incapable of performing Grantee’s essential job functions with or without reasonable accommodation as required by law due to injury, illness, or other incapacity (physical or mental).

(f)“Good Reason” shall have the meaning set forth in any applicable agreement between the Company and Grantee regarding Grantee’s Service with the Company and, if “Good Reason” is not so defined, shall exist in the event any of the following actions are taken without Grantee’s consent: (i) Grantee’s authority with the Company is, or Grantee’s duties or responsibilities based on Grantee’s position with the Company or any employment agreement or arrangement between Grantee and the Company are, materially diminished relative to Grantee’s authority, duties and responsibilities as in effect immediately prior to such change; provided, however, that in no event shall removal of Grantee from the position of manager, director or officer of any direct or indirect Affiliate of the Company in connection with any corporate restructuring constitute Good Reason; (ii) a material diminution in Grantee’s base salary or retainer compensation as in effect immediately prior to such diminution; provided, that, an across-the-board reduction in the base compensation and benefits of all Service Providers of the Company by the same percentage amount (or under the same terms and conditions) as part of a general base compensation reduction and/or benefit reduction shall not constitute such a qualifying material diminution; (iii) a material relocation of Grantee’s primary work location more than 75 miles away from the then-current primary work location; or (iv) any material breach by the Company of any provision of this Agreement or any employment agreement or arrangement between Grantee and the Company.

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(g)“Grantee” means you, the employee of the Company specified in the grant notice that you received from the Company on or about [DATE].

(h)       “Grant Date” means [DATE].

(i)        “Installment” means a portion of Covered Shares.

Capitalized terms used herein without definition have the meanings ascribed to such terms in the Plan.  Except where the context clearly implies or indicates the contrary, a word, term, or phrase used in the Plan is similarly used in this Agreement.

2.  Award.  Grantee is hereby granted the number of Covered Shares set forth in paragraph 1.

3.  Delivery of Covered Shares.  Covered Shares shall be registered in book entry form with the Company’s transfer agent.  During the applicable Restricted Period, Covered Shares may carry the following legend or any other legend the Board or the Committee (if so authorized) deems applicable:

“THESE SECURITIES ARE SUBJECT TO THE VESTING RESTRICTIONS AND OTHER PROVISIONS OF THE BONANZA CREEK ENERGY, INC. 2011 LONG TERM INCENTIVE PLAN AND THE RESTRICTED STOCK AGREEMENT BETWEEN BONANZA CREEK ENERGY, INC. AND THE HOLDER OF THESE SECURITIES.”

4.  Restricted Period.  The “Restricted Period” for each Installment of Covered Shares shall begin on the Grant Date and end on the date scheduled below applicable to such Installment: (1)

INSTALLMENT	RESTRICTED PERIOD WILL END ON:
[FRACTION OF COVERED SHARES] of the Covered Shares	[DATE]

[ADD ADDITIONAL ROWS AS APPROPRIATE]

Covered Shares may not be sold, assigned, transferred, pledged or otherwise encumbered prior to the expiration of the Restricted Period applicable to such Installment of Covered Shares.

5.  Transfer and Forfeiture of Shares.  Grantee shall forfeit any Installment of Covered Shares for which the Restricted Period has not expired as of a Date of Termination.  If a Date of Termination does not occur during a Restricted Period with respect to an Installment of the Covered Shares, then, at the end of the Restricted Period that is applicable for such Installment, Grantee shall become vested in those Covered Shares, and such Installment shall be transferred to Grantee free of all restrictions otherwise imposed by this Agreement.

(1)  Vesting terms to be confirmed for each grant.

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Notwithstanding the foregoing, in the event of a Change in Control any Installment of Covered Shares for which the Restricted Period has not expired as of the date of such Change in Control shall become vested immediately prior to the effective time of such Change in Control and such Installment shall be transferred to Grantee free of all restrictions otherwise imposed by this Agreement.

6.  Withholding.  The grant and vesting of shares of Stock under this Agreement are subject to withholding of all applicable taxes.  At the election of Grantee, and subject to such rules and limitations as may be established by the Board from time to time, such withholding obligations may be satisfied through the surrender of shares of Stock (a) which Grantee already owns, or (b) to which Grantee is otherwise entitled under the Plan; provided, however, that shares described in this clause (b) may be used to satisfy not more than the Company’s minimum statutory withholding obligation (based on minimum statutory withholding rates for federal and state tax purposes, including payroll taxes, that are applicable to such taxable income).

7.  Dividends.  Grantee shall not be prevented from receiving dividends and distributions paid on the Covered Shares merely because those shares are subject to the restrictions imposed by this Agreement and the Plan; provided, however that no dividends or distributions shall be payable to or for the benefit of Grantee with respect to record dates for such dividends or distributions for any Covered Shares occurring on or after the date, if any, on which Grantee has forfeited those shares.

8.  Voting.  Grantee shall not be prevented from voting the Covered Shares merely because those shares are subject to the restrictions imposed by this Agreement and the Plan; provided, however, that Grantee shall not be entitled to vote Covered Shares with respect to record dates for any Covered Shares occurring on or after the date, if any, on which Grantee has forfeited those shares.

9.  Heirs and Successors.  This Agreement shall be binding upon, and inure to the benefit of, the Company and its successors and assigns, and upon any person acquiring, whether by merger, consolidation, purchase of assets or otherwise, all or substantially all of the Company’s assets and business.  If any rights of Grantee or benefits distributable to Grantee under this Agreement have not been exercised or distributed, respectively, at the time of Grantee’s death, such rights shall be exercisable by the Designated Beneficiary, and such benefits shall be distributed to the Designated Beneficiary, in accordance with the provisions of this Agreement and the Plan.  If a deceased Grantee fails to designate a beneficiary, or if the Designated Beneficiary does not survive Grantee, any rights that would have been exercisable by Grantee and any benefits distributable to Grantee shall be exercised by or distributed to the legal representative of the estate of Grantee.  If a deceased Grantee designates a beneficiary and the Designated Beneficiary survives Grantee but dies before the Designated Beneficiary’s exercise of all rights under this Agreement or before the complete distribution of benefits to the Designated Beneficiary under this Agreement, then any rights that would have been exercisable by the Designated Beneficiary shall be exercised by the legal representative of the estate of the Designated Beneficiary, and any benefits distributable to the Designated Beneficiary shall be distributed to the legal representative of the estate of the Designated Beneficiary.

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10.  Administration.  The authority to manage and control the operation and administration of this Agreement shall be vested in the Board, and the Board shall have all powers with respect to this Agreement as it has with respect to the Plan.  Any interpretation of the Agreement by the Board and any decision made by it with respect to the Agreement is final and binding on all persons.

11.  Plan Governs.  Notwithstanding anything in this Agreement to the contrary, the terms of this Agreement shall be subject to the terms of the Plan, a copy of which may be obtained by Grantee from the office of the Secretary of the Company; and this Agreement is subject to all interpretations, amendments, rules and regulations promulgated by the Board from time to time pursuant to the Plan.

12.  Fractional Shares.  In lieu of issuing a fraction of a share of Stock resulting from an adjustment of the Award pursuant to Section 17.4 of the Plan or otherwise, the Company will be entitled to pay to Grantee an amount equal to the fair market value of such fractional share.

13.  Not An Employment Contract.  The Award will not confer on Grantee any right with respect to continuance of employment or other service with the Company or any Subsidiary, nor will it interfere in any way with any right the Company or any Subsidiary would otherwise have to terminate or modify the terms of such Grantee’s Service at any time.

14.  Notices.  Any written notices provided for in this Agreement or the Plan shall be in writing and shall be deemed sufficiently given if either hand delivered or if sent by fax or overnight courier, or by postage paid first class mail.  Notices sent by mail shall be deemed received three business days after mailing but in no event later than the date of actual receipt.  Notices shall be directed, if to Grantee, at Grantee’s address indicated by the Company’s records, or if to the Company, at the Company’s principal executive office.

15.  Amendment.  This Agreement may be amended in accordance with the provisions of the Plan, and may otherwise be amended by written agreement of Grantee and the Company without the consent of any other person.

16.  Section 83(b) Election.  With the prior consent of the President, Chief Executive Officer, Chief Financial Officer or General Counsel of the Company, Grantee may, within 30 days of the Grant Date, file an election under section 83(b) of the Code with the Internal Revenue Service with respect to the Covered Shares (a “Section 83(b) Election”).  Within five business days of filing a Section 83(b) Election, Grantee shall provide a copy of such completed election form to the Company at the following address: 410 17th Street, Suite 1400, Denver, CO 80202, Attention: General Counsel.  Grantee acknowledges that any Section 83(b) Election is Grantee’s sole responsibility, and additionally acknowledges that the Company has hereby advised Grantee to consult with a financial or tax advisor of Grantee’s own choosing with regard to the federal and state tax considerations resulting from the Award and/or the effect of filing a Section 83(b) Election.  The Company is unable to give Grantee any advice or counseling with respect to federal and state tax matters.

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EX-10.5

Exhibit 10.5

AMENDMENT NO. 4

This AMENDMENT NO. 4 (the “Amendment”) dated as of July 31, 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, and Amendment No. 3 & Agreement dated as of May 8, 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 restating the definition of “Issuing Lender” in its entirety with the following:

“Issuing Lender” means KeyBank National Association and any successor issuing lender or additional issuing lender pursuant to Section 9.06.

(b)The Credit Agreement is hereby amended by adding the following new Section 1.06 to the Credit Agreement:

Section 1.06Issuing Lenders.  In the event that, pursuant to Section 9.06 below, multiple Issuing Lenders are appointed under this Credit Agreement, all references to “Issuing Lender” shall refer to all Issuing Lenders collectively, “any Issuing Lender” or “the applicable Issuing Lender” as the situation may require.

(c)Section 2.07(a)(i) of the Credit Agreement is hereby deleted in its entirety and replaced with the following:

(i)if such issuance, increase, or extension would cause the Letter of Credit Exposure to exceed the lesser of (A) $100,000,000 and (B) an amount equal to the lesser of (1) the aggregate Commitments at such time and (2) the Borrowing Base in effect at such time minus, in each case under this clause (B), the sum of the aggregate outstanding principal amount of all Advances at such time;

(d)Section 2.07(b) of the Credit Agreement is hereby deleted in its entirety and replaced with the following:

(b)Participations.  Upon the date of the issuance or increase of a Letter of Credit, the Issuing Lender shall be deemed to have sold to each other Lender and each other Lender shall have been deemed to have purchased from the Issuing Lender a participation in the related Letter of Credit Obligations equal to such Lender’s Pro Rata Share at such date and such sale and purchase shall otherwise be in accordance with the terms of this Agreement.  The Issuing Lender shall promptly notify the Administrative Agent who shall promptly notify each such participant Lender by telephone, or facsimile of each Letter of Credit issued, increased, or extended and the actual dollar amount of such Lender’s participation in such Letter of Credit.

(e)Section 2.07(c) of the Credit Agreement is hereby deleted in its entirety and replaced with the following:

(c)Issuing.  Each Letter of Credit shall be issued, increased, or extended pursuant to a Letter of Credit Application (or by telephone notice promptly confirmed in writing by a Letter of Credit Application), given by the Borrower not later than noon (Houston, Texas time) on the fifth Business Day before the date of the

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proposed issuance, increase, or extension of such Letter of Credit (or such earlier day as shall be agreed by the Issuing Lender),  and the Issuing Lender shall promptly notify the Administrative Agent who shall give to each other Lender prompt notice thereof by telex, telephone, or facsimile.  Each Letter of Credit Application shall be delivered by facsimile or by mail specifying the information required therein; provided that if such Letter of Credit Application is delivered by facsimile, the Borrower shall follow such facsimile with an original by mail.  After the Issuing Lender’s receipt of such Letter of Credit Application (by facsimile or by mail) and upon fulfillment of the applicable conditions set forth in Article III, the Issuing Lender shall issue, increase, or extend such Letter of Credit for the account of the Borrower or applicable Subsidiary of the Borrower.  Each Letter of Credit Application shall be irrevocable and binding on the Borrower.

(f)Section 2.08(b)(i)(B) of the Credit Agreement is hereby deleted in their entirety and replaced with the following:

(B) to the Issuing Lender, a fronting fee for each Letter of Credit issued by the Issuing Lender in an amount to be mutually agreed upon by the Issuing Lender and the Borrower.

(g)Section 9.06 of the Credit Agreement is hereby amended by adding the following  new sentence to the end thereof:

The Administrative Agent may, with the consent of the Borrower and the Lender in question, appoint any Lender hereunder as an Issuing Lender in addition to KeyBank National Association or any successor of KeyBank National Association in such capacity.

Section 4.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 5.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 6.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.

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Section 7.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 8.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 9.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 10.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 11.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 12.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 12, AND IS FREELY AND VOLUNTARILY ENTERING INTO THIS AMENDMENT, AND HEREBY AGREES TO WAIVE ANY CLAIM THAT THE TERMS

5

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

Section 13.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]

6

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
	LIBERTY ENERGY COMPANY, LLC
	By:	/s/ Michael R. Starzer
		Michael R. Starzer
		President & Chief Executive Officer

Signature Page to Amendment No. 4

Bonanza Creek Energy, Inc.

BONANZA CREEK ENERGY MIDSTREAM,
LLC
By:	/s/ Michael R. Starzer
	Michael R. Starzer
	President & Chief Executive Officer
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. 4

Bonanza Creek Energy, Inc.

ADMINISTRATIVE AGENT/ ISSUING LENDER/LENDER:	KEY BANK NATIONAL ASSOCIATION, as Administrative Agent, Issuing Lender, and a Lender
	By:	/s/ Paul J. Pace
	Name:	Paul J. Pace
	Title:	Sr. Vice President

Signature Page to Amendment No. 4

Bonanza Creek Energy, Inc.

LENDER:	COMPASS BANK, as a Lender
	By:	/s/ Dorothy Marchand
	Name:	Dorothy Marchand
	Title:	Senior Vice President

Signature Page to Amendment No. 4

Bonanza Creek Energy, Inc.

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

Signature Page to Amendment No. 4

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. 4

Bonanza Creek Energy, Inc.

LENDER:	WELLS FARGO BANK. N.A., as a Lender
	By:	/s/ Jonathon Hemok
	Name:	Jonathon Hemok
	Title:	AVP

Signature Page to Amendment No. 4

Bonanza Creek Energy, Inc.

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

Signature Page to Amendment No. 4

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. 4

Bonanza Creek Energy, Inc.

EX-31.1

Exhibit 31.1

CERTIFICATION OF THE CHIEF 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 June 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: August 13, 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 CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13a-14(a)

I, James R. Casperson, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q for the period ended June 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: August 13, 2012
	/s/ James R. Casperson
	James R. Casperson Executive Vice President and Chief Financial Officer of Bonanza Creek Energy, Inc.

EX-32.1

Exhibit 32.1

Certification of the Chief 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 June 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: August 13, 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 Chief 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 June 30, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, James R. Casperson, Chief Financial 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: August 13, 2012
	/s/ James R. Casperson
	James R. Casperson Executive Vice President and Chief Financial Officer of Bonanza Creek Energy, Inc.

XML

STOCKHOLDERS' EQUITY: (Details) (USD $)	3 Months Ended		6 Months Ended				1 Months Ended	6 Months Ended		1 Months Ended	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012 MIP	Dec. 23, 2010 MIP	Dec. 31, 2010 MIP Restricted shares	Jun. 30, 2012 MIP Restricted shares	Jun. 30, 2012 BCEC Management Incentive Plan	Jun. 30, 2012 2011 Long Term Incentive Plan Restricted shares	Jun. 30, 2012 2011 Long Term Incentive Plan Restricted shares	Jun. 14, 2012 2011 Long Term Incentive Plan Restricted shares
STOCKHOLDERS' EQUITY
Shares available under the plan						10,000
Shares granted							437,787		73,197	540,000
Share price (in dollars per share)						$ 17.00						$ 15.38
Vesting period							3 years
Non-cash compensation expense	$ 795,774	$ 60,000	$ 1,466,338	$ 60,000	$ 1,223,000
Unrecognized compensation costs								$ 6,019,000
Unrecognized compensation costs recognition period								2 years 6 months			2 years 8 months 12 days
Vesting portion of shares											0.33

XML

ACCOUNTS PAYABLE AND ACCRUED EXPENSES: (Details) (USD $)	Jun. 30, 2012	Dec. 31, 2011
Accounts payable and accrued expenses contain the following:
Drilling and completion costs	$ 53,730,952	$ 14,153,449
Accounts payable trade	2,528,046	4,976,979
Ad valorem taxes	190,627	1,781,021
Accrued general and administrative cost	2,494,509	1,713,708
Accrued initial public offering expenses		1,258,791
Lease operating expense	2,361,200	2,128,470
Accrued reclamation cost	400,000	400,000
Accrued interest	257,797	17,965
Accrued oil and gas hedging	186,973	353,897
Production taxes and other	2,281,090	284,046
Total accounts payable and accrued expenses	$ 64,431,194	$ 27,068,326

XML

DIVESTITURES:

6 Months Ended

Jun. 30, 2012

DIVESTITURES:

DIVESTITURES:

3. DIVESTITURES:

During June of 2012, the Company began marketing, with an intent to sell, all of its oil and gas properties in California.  In accordance with ASC Topic 360, 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 although the Company has not yet reached any definitive agreement with a counter party to sell the properties.  The carrying amounts of the major classes of assets and liabilities related to the operation of these properties that are held for sale as of June 30, 2012 and December 31, 2011 are presented below:

	As of June 30, 2012			As of December 31, 2011
PROPERTY AND EQUIPMENT:
Oil and gas properties, successful efforts method:
Proved properties	$	13,061,985		$	13,060,597
Unproved properties	32,013			32,013
Wells in progress	581,387			167,198
Total property and equipment	13,675,385			13,259,808
Less accumulated depletion and depreciation	(4,886,425		)	(3,364,300		)
Net property and equipment	$	8,788,960		$	9,895,508
ASSET RETIREMENT OBLIGATIONS	$	1,014,974		$	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 six month periods ended June 30, 2012 and 2011 are presented below.

	Three Months Ended June 30		Three Months Ended June 30		Six MonthsEnded June 30		Six Months Ended June 30
	2012		2011		2012		2011
NET REVENUES:
Oil and gas sales	$	2,013,861	$	1,798,673	$	3,725,759	$	3,469,295
Total revenue	2,013,861		1,798,673		3,725,759		3,469,295
OPERATING EXPENSES:
Lease operating	733,547		685,137		1,401,290		1,624,287
Severance and ad valorem taxes	19,863		69,316		115,489		82,449
Exploration	187		5,935		10,789		6,595
Depreciation, depletion and amortization	752,053		767,586		1,578,990		1,636,541
TOTAL COSTS AND EXPENSES	1,505,650		1,527,974		3,106,558		3,349,872
INCOME FROM OPERATIONS ASSOCIATED WITH OIL AND GAS PROPERTIES HELD FOR SALE	$	508,211	$	270,699	$	619,201	$	119,423

XML

FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION: (Details) (Recurring, Commodity derivative, USD $)	Jun. 30, 2012	Dec. 31, 2011
Level 2
Financial assets and liabilities accounted for at fair value
Derivative assets	$ 2,526,789	$ 1,094,055
Derivative liabilities	3,333,129	6,740,213
Level 3
Financial assets and liabilities accounted for at fair value
Derivative assets	6,918,799	881,822
Derivative liabilities		$ 1,115,595

XML

COMMITMENTS AND CONTINGENT LIABILITIES: (Details 2) (USD $) In Millions, unless otherwise specified		6 Months Ended
	Jun. 30, 2011 Current President and Chief Executive Officer vs. former Chairman of BCEC director	Jun. 30, 2012 Mr. Bennett's claims
Legal Proceedings
Number of non-executive directors in special litigation committee	3
Expenses related to litigation		$ 1.2

XML

FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION: (Details 2) (Commodity derivatives, USD $)	6 Months Ended
	Jun. 30, 2012
Commodity derivatives
Derivative Asset
Beginning net asset (liability) balance	$ 881,822
Net increase in fair value	330,830
Net realized (gain) on settlement	(181,946)
New derivatives	411,178
Ending net asset (liability) balance	1,441,884
Derivative (Liability)
Beginning net asset (liability) balance	(1,115,595)
Net increase in fair value	8,014,163
Net realized (gain) on settlement	(121,686)
New derivatives	(1,299,967)
Ending net asset (liability) balance	$ 5,476,915

XML

FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION: (Details 3) (Commodity derivatives)	Jun. 30, 2012 bblpermonth
July 1 - December 31, 2012
Derivative contract
Notional Volume	77,956
July 1 - December 31, 2012 | $85.22
Derivative contract
Notional Volume	29,563
Price (in dollars per unit)	85.22
July 1 - December 31, 2012 | $6.75
Derivative contract
Notional Volume	16,625
Price (in dollars per unit)	6.75
January 1 - December 31, 2013
Derivative contract
Notional Volume	34,218
January 1 - October 31, 2013 | $81.72
Derivative contract
Notional Volume	16,285
Price (in dollars per unit)	81.72
January 1 - October 31, 2013 | $6.40
Derivative contract
Notional Volume	15,481
Price (in dollars per unit)	6.40
Average Floor | July 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)	92.10
Average Ceiling | July 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)	108.91

XML

BASIS OF PRESENTATION:

6 Months Ended

Jun. 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, Bonanza Creek Energy Midstream, LLC and Liberty Energy Company, 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.

XML

FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION: (Details 4) (Fair Value, USD $)	Jun. 30, 2012	Dec. 31, 2011
Derivatives measured at fair value
Total	$ 6,112,459
Commodity derivatives | Current derivative assets
Derivatives measured at fair value
Derivative asset	7,369,944	1,297,403
Commodity derivatives | Long term derivative assets
Derivatives measured at fair value
Derivative asset	2,075,644	678,474
Commodity derivatives | Current derivative liability
Derivatives measured at fair value
Derivative liability	(2,536,623)	(5,276,633)
Commodity derivatives | Long term derivative liability
Derivatives measured at fair value
Derivative liability	$ (796,506)	$ (2,579,175)

XML

CONSOLIDATED BALANCE SHEETS (USD $)	Jun. 30, 2012	Dec. 31, 2011
CURRENT ASSETS:
Cash and cash equivalents	$ 2,605,378	$ 2,089,674
Accounts receivable:
Oil and gas sales	24,346,613	17,850,719
Other	12,012,855	5,696,825
Prepaid expenses and other	1,899,507	1,868,016
Inventory of oilfield equipment	2,609,464	3,324,368
Derivative asset	7,369,944	1,297,403
Total current assets	50,843,761	32,127,005
OIL AND GAS PROPERTIES-using the successful efforts method of accounting:
Proved properties	647,233,892	547,878,188
Unproved properties	15,851,016	15,848,703
Wells in progress	68,775,281	23,783,142
OIL AND GAS PROPERTIES-using the successful efforts method of accounting	731,860,189	587,510,033
Less: accumulated depreciation, depletion and amortization	(49,330,212)	(26,759,043)
OIL AND GAS PROPERTIES-net, using the successful efforts method of accounting	682,529,977	560,750,990
NATURAL GAS PLANT	61,707,490	56,910,232
Less: accumulated depreciation	(2,287,223)	(1,286,129)
NATURAL GAS PLANT-net	59,420,267	55,624,103
PROPERTY AND EQUIPMENT	3,452,170	1,983,037
Less: accumulated depreciation	(405,824)	(128,731)
PROPERTY AND EQUIPMENT-net	3,046,346	1,854,306
Oil and gas properties held for sale less accumulated depreciation, depletion, and amortization - Note 3	8,788,960	9,895,508
LONG-TERM DERIVATIVE ASSET	2,075,644	678,474
OTHER ASSETS, net	3,345,531	3,418,626
TOTAL ASSETS	810,050,486	664,349,012
CURRENT LIABILITIES:
Accounts payable and accrued expenses	64,431,194	27,068,326
Oil and gas revenue distribution payable	8,485,093	6,185,983
Derivative liability	2,536,623	5,276,633
Total current liabilities	75,452,910	38,530,942
LONG-TERM LIABILITIES:
Bank revolving credit	62,600,000	6,600,000
Ad valorem taxes	6,354,355	3,014,023
Derivative liability	796,506	2,579,175
Deferred income taxes, net	98,416,935	79,603,633
Asset retirement obligations	6,929,670	6,039,723
TOTAL LIABILITIES	250,550,376	136,367,496
COMMITMENTS AND CONTINGENCIES (Note 7)
STOCKHOLDERS' EQUITY:
Preferred stock, $.001 par value, 25,000,000 shares authorized, 0 outstanding
Common stock, $.001 par value, 225,000,000 shares authorized, 40,011,894 and 39,477,584 issued and outstanding, respectively	40,012	39,478
Additional paid-in capital	516,878,387	515,412,583
Retained earnings	42,581,711	12,529,455
Total stockholders' equity	559,500,110	527,981,516
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 810,050,486	$ 664,349,012

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 30,052,256	$ 8,034,665
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	25,614,523	13,779,037
Deferred income taxes	18,813,302	4,692,510
Non-cash compensation expense	1,466,338	60,000
Exploration	1,575,494
Amortization of deferred financing costs	464,377	447,197
Valuation (increase) decrease in commodity derivatives	(11,992,390)	1,172,455
Other	3,334	(39,868)
(Increase) decrease in operating assets:
Accounts receivable	(12,811,924)	(4,219,346)
Prepaid expenses and other assets	(31,491)	(135,423)
(Decrease) increase in operating liabilities:
Accounts payable and accrued liabilities	3,381,752	(1,884,356)
Settlement of asset retirement obligations	(146,125)	(80,435)
Net cash provided by operating activities	56,389,446	21,826,436
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of oil and gas properties	(553,731)	(777,621)
Exploration and development of oil and gas properties	(102,945,699)	(46,265,409)
Natural gas plant capital expenditures	(6,510,563)	(11,141,877)
Proceeds from note receivable		986,906
Decrease in restricted cash	232,580
Additions to property and equipment-non oil and gas	(1,469,133)	(214,021)
Net cash used in investing activities	(111,246,546)	(57,412,022)
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in bank revolving credit	56,000,000	103,200,000
Payment on bank revolving credit		(65,800,000)
Deferred financing costs	(627,196)	(1,814,414)
Net cash provided by financing activities	55,372,804	35,585,586
NET INCREASE IN CASH AND CASH EQUIVALENTS	515,704
CASH AND CASH EQUIVALENTS:
Beginning of period	2,089,674
End of period	2,605,378
SUPPLEMENTAL CASH FLOW DISCLOSURE:
Cash paid for interest	512,000	943,555
Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition	$ 39,577,503	$ 4,694,941

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FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION: (Tables)

6 Months Ended

Jun. 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 June 30, 2012 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3
Commodity derivative assets	$	—	$	2,526,789	$	6,918,799
Commodity derivative liabilities	$	—	$	3,333,129	$	—

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 June 30, 2012:

	Derivative Asset			Derivative Liability
Beginning net asset (liability) balance	$	881,822		$	(1,115,595	)
Net increase in fair value	330,830			8,014,163
Net realized (gain) on settlement	(181,946		)	(121,686		)
New derivatives	411,178			(1,299,967		)
Transfers in (out) of Level 3	—			—
Ending net asset (liability) balance	$	1,441,884		$	5,476,915

Schedule of derivative commodity contracts

Contract Term	Notional Volume	Average Floor		Average Ceiling		Average Fixed Price
July 1 - December 31, 2012	77,956 Bbl./Month	$	90.00	$	106.05	—
January 1 - December 31, 2013	34,218 Bbl./Month	$	92.10	$	108.91	—
July 1 - December 31, 2012	29,563 Bbl./Month	—		—		$	85.22
January 1 - December 31, 2013	16,285 Bbl./Month	—		—		$	81.72
July 1 - December 31, 2012	16,625 MMBTU/Month	—		—		$	6.75
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	$	7,369,944
Commodity derivatives	Long-term derivative assets	2,075,644
Liability
Commodity derivatives	Current derivative liability	(2,536,623		)
Commodity derivatives	Long-term derivative liability	(796,506		)
Total		$	6,112,459

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DIVESTITURES: (Details) (USD $)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
DIVESTITURES:
Period within which sale of asset takes place to classify it as held for sale			1 year
Oil and gas properties, successful efforts method;
Proved properties	$ 647,233,892		$ 647,233,892		$ 547,878,188
Unproved properties	15,851,016		15,851,016		15,848,703
OIL AND GAS PROPERTIES-using the successful efforts method of accounting	731,860,189		731,860,189		587,510,033
Less accumulated depletion and depreciation	(49,330,212)		(49,330,212)		(26,759,043)
OIL AND GAS PROPERTIES-net, using the successful efforts method of accounting	682,529,977		682,529,977		560,750,990
NET REVENUES
Oil and gas sales	51,455,094	24,151,668	99,285,525	44,693,663
OPERATING EXPENSES:
Lease operating	6,954,397	3,679,573	14,061,728	7,354,447	2,128,470
Severance and ad valorem taxes	2,769,425	1,396,514	6,365,234	2,436,300
Exploration	2,014,531	22,798	3,204,654	547,602
Depreciation, depletion and amortization			25,614,523	13,779,037
TOTAL COSTS AND EXPENSES	31,883,228	14,420,993	60,742,252	27,417,500
INCOME FROM OPERATIONS	19,571,866	9,730,675	38,543,273	17,276,163
Oil and gas properties in California
Oil and gas properties, successful efforts method;
Proved properties	13,061,985		13,061,985		13,060,597
Unproved properties	32,013		32,013		32,013
Wells in progress	581,387		581,387		167,198
OIL AND GAS PROPERTIES-using the successful efforts method of accounting	13,675,385		13,675,385		13,259,808
Less accumulated depletion and depreciation	(4,886,425)		(4,886,425)		(3,364,300)
OIL AND GAS PROPERTIES-net, using the successful efforts method of accounting	8,788,960		8,788,960		9,895,508
ASSET RETIREMENT OBLIGATIONS	1,014,974		1,014,974		975,562
NET REVENUES
Oil and gas sales	2,013,861	1,798,673	3,725,759	3,469,295
Total revenue	2,013,861	1,798,673	3,725,759	3,469,295
OPERATING EXPENSES:
Lease operating	733,547	685,137	1,401,290	1,624,287
Severance and ad valorem taxes	19,863	69,316	115,489	82,449
Exploration	187	5,935	10,789	6,595
Depreciation, depletion and amortization	752,053	767,586	1,578,990	1,636,541
TOTAL COSTS AND EXPENSES	1,505,650	1,527,974	3,106,558	3,349,872
INCOME FROM OPERATIONS	$ 508,211	$ 270,699	$ 619,201	$ 119,423

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ORGANIZATION AND BUSINESS:

6 Months Ended

Jun. 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 June 30, 2012, the Company’s assets and operations are concentrated primarily in southern Arkansas and in the Wattenberg field and North Park Basin in the Rocky Mountains.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Jun. 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	40,011,894	39,477,584
Common stock, shares outstanding	40,011,894	39,477,584

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SUBSEQUENT EVENTS:

6 Months Ended

Jun. 30, 2012

SUBSEQUENT EVENTS:

SUBSEQUENT EVENTS:

11. SUBSEQUENT EVENTS:

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 for approximately $60,000,000.  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.

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Document and Entity Information	6 Months Ended
	Jun. 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	Jun. 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	40,011,894
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2

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BASIS OF PRESENTATION: (Policies)

6 Months Ended

Jun. 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, Bonanza Creek Energy Midstream, LLC and Liberty Energy Company, 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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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
NET REVENUES
Oil and gas sales	$ 51,455,094	$ 24,151,668	$ 99,285,525	$ 44,693,663
OPERATING EXPENSES:
Lease operating	6,954,397	3,679,573	14,061,728	7,354,447
Severance and ad valorem taxes	2,769,425	1,396,514	6,365,234	2,436,300
Exploration	2,014,531	22,798	3,204,654	547,602
Depreciation, depletion and amortization	13,034,490	6,624,007	24,035,533	12,142,496
General and administrative (including $795,774, $60,000, $1,466,338, and $60,000, respectively, of stock compensation)	7,110,385	2,698,101	13,075,103	4,936,655
Total operating expenses	31,883,228	14,420,993	60,742,252	27,417,500
INCOME FROM OPERATIONS	19,571,866	9,730,675	38,543,273	17,276,163
OTHER INCOME (EXPENSE):
Other income (loss)	45,437	(165,225)	7,710	(97,279)
Interest expense	(654,693)	(852,005)	(1,216,209)	(1,564,777)
Unrealized (loss) in fair value of commodity derivatives	15,368,221	4,282,091	11,992,390	(1,172,455)
Realized (loss) in fair value of commodity derivatives	130,332	(1,057,980)	(1,080,807)	(1,833,900)
Total other income (loss)	14,889,297	2,206,881	9,703,084	(4,668,411)
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES	34,461,163	11,937,556	48,246,357	12,607,752
Deferred income taxes (Note 10)	(13,267,610)	(4,400,505)	(18,574,910)	(4,648,478)
INCOME FROM CONTINUING OPERATIONS	21,193,553	7,537,051	29,671,447	7,959,274
DISCONTINUED OPERATIONS (Note 3)
Income from operations associated with oil and gas properties held for sale	508,211	270,699	619,201	119,423
Deferred income taxes benefit	(195,661)	(100,005)	(238,392)	(44,032)
Income associated with oil and gas properties held for sale	312,550	170,694	380,809	75,391
NET INCOME	$ 21,506,103	$ 7,707,745	$ 30,052,256	$ 8,034,665
BASIC AND DILUTED INCOME PER SHARE
Income from continuing operations (in dollars per share)	$ 0.53	$ 0.25	$ 0.75	$ 0.28
Income (loss) from discontinued operations (in dollars per share)	$ 0.01	$ 0.01	$ 0.01
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK-BASIC (in shares)	39,474,011	29,122,521	39,475,797	29,122,521
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK-DILUTED (in shares)	39,474,011	29,122,521	39,475,797	29,122,521

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SENIOR SECURED REVOLVING CREDIT FACILITY:

6 Months Ended

Jun. 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 June 30, 2012 and is subject to semi-annual re-determinations in April and October of each year. 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 June 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:

6 Months Ended

Jun. 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	$	53,730,952	$	14,153,449
Accounts payable trade	2,528,046		4,976,979
Ad valorem taxes	190,627		1,781,021
Accrued general and administrative cost	2,494,509		1,713,708
Accrued initial public offering expenses	—		1,258,791
Lease operating expense	2,361,200		2,128,470
Accrued reclamation cost	400,000		400,000
Accrued interest	257,797		17,965
Accrued oil and gas hedging	186,973		353,897
Production taxes and other	2,281,090		284,046
	$	64,431,194	$	27,068,326

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ORGANIZATION AND BUSINESS: (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended
	Dec. 31, 2010	Dec. 23, 2010
Organization and Business
Common stock	$ 265
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%
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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DIVESTITURES: (Tables)

6 Months Ended

Jun. 30, 2012

DIVESTITURES:

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

	As of June 30, 2012			As of December 31, 2011
PROPERTY AND EQUIPMENT:
Oil and gas properties, successful efforts method:
Proved properties	$	13,061,985		$	13,060,597
Unproved properties	32,013			32,013
Wells in progress	581,387			167,198
Total property and equipment	13,675,385			13,259,808
Less accumulated depletion and depreciation	(4,886,425		)	(3,364,300		)
Net property and equipment	$	8,788,960		$	9,895,508
ASSET RETIREMENT OBLIGATIONS	$	1,014,974		$	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 June 30		Three Months Ended June 30		Six MonthsEnded June 30		Six Months Ended June 30
	2012		2011		2012		2011
NET REVENUES:
Oil and gas sales	$	2,013,861	$	1,798,673	$	3,725,759	$	3,469,295
Total revenue	2,013,861		1,798,673		3,725,759		3,469,295
OPERATING EXPENSES:
Lease operating	733,547		685,137		1,401,290		1,624,287
Severance and ad valorem taxes	19,863		69,316		115,489		82,449
Exploration	187		5,935		10,789		6,595
Depreciation, depletion and amortization	752,053		767,586		1,578,990		1,636,541
TOTAL COSTS AND EXPENSES	1,505,650		1,527,974		3,106,558		3,349,872
INCOME FROM OPERATIONS ASSOCIATED WITH OIL AND GAS PROPERTIES HELD FOR SALE	$	508,211	$	270,699	$	619,201	$	119,423

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STOCKHOLDERS' EQUITY:

6 Months Ended

Jun. 30, 2012

STOCKHOLDERS' EQUITY:

STOCKHOLDERS' EQUITY:

9. STOCKHOLDERS’ EQUITY:

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 its 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 $1,223,000 was recorded during the six months ended June 30, 2012 and there was approximately $6,019,000 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 2.5 years.

BCEC Management Incentive Plan—As of June 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.

On June 14, 2012, the Company granted 540,000 shares of restricted common stock under its 2011 Long Term Incentive Plan to officers and certain employees.  For accounting purposes, these shares were valued at $15.38, the closing price of its 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.

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COMMITMENTS AND CONTINGENT LIABILITIES:

6 Months Ended

Jun. 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		Line of Credit		Total
2012	$	537,233	$	—	$	537,233
2013	1,098,709		—		1,098,709
2014	1,085,740		—		1,085,740
2015	1,111,256		—		1,111,256
2016 and thereafter	2,235,743		62,600,000		64,835,743
	$	6,068,681	$	62,600,000	$	68,668,681

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—The Company may from time to time be involved in various legal actions arising in the normal course of business. During the second quarter of 2011, its Board of Directors formed a Special Litigation Committee comprised of three non-executive directors to investigate the merits of a demand for arbitration against its current President and Chief Executive Officer from the former Chairman of BCEC related to the management of BCOC and BCEC primarily during the 2005-2006 time period. These demands do not allege any wrongdoing by or claims against the Company. The Special Litigation Committee retained outside independent advisors to conduct the investigation and concluded that the allegations lack merit.  An arbitration hearing commenced in July 2012 and it is not clear when a final decision will be rendered.  Mr. Starzer plans to continue to vigorously defend against Mr. Bennett’s claims.  During the period from January 1, 2012 through June 30, 2012 the Company incurred approximately $1.2 million related to Mr. Bennett’s claims.

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FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION:

6 Months Ended

Jun. 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.

ASC 820 requires 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 June 30, 2012 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3
Commodity derivative assets	$	—	$	2,526,789	$	6,918,799
Commodity derivative liabilities	$	—	$	3,333,129	$	—

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 June 30, 2012:

	Derivative Asset			Derivative Liability
Beginning net asset (liability) balance	$	881,822		$	(1,115,595	)
Net increase in fair value	330,830			8,014,163
Net realized (gain) on settlement	(181,946		)	(121,686		)
New derivatives	411,178			(1,299,967		)
Transfers in (out) of Level 3	—			—
Ending net asset (liability) balance	$	1,441,884		$	5,476,915

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

Contract Term	Notional Volume	Average Floor		Average Ceiling		Average Fixed Price
July 1 - December 31, 2012	77,956 Bbl./Month	$	90.00	$	106.05	—
January 1 - December 31, 2013	34,218 Bbl./Month	$	92.10	$	108.91	—
July 1 - December 31, 2012	29,563 Bbl./Month	—		—		$	85.22
January 1 - December 31, 2013	16,285 Bbl./Month	—		—		$	81.72
July 1 - December 31, 2012	16,625 MMBTU/Month	—		—		$	6.75
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 June 30, 2012:

Derivatives	Balance Sheet Location	Fair Value
Asset
Commodity derivatives	Current derivative assets	$	7,369,944
Commodity derivatives	Long-term derivative assets	2,075,644
Liability
Commodity derivatives	Current derivative liability	(2,536,623		)
Commodity derivatives	Long-term derivative liability	(796,506		)
Total		$	6,112,459

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.

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INCOME TAXES:

6 Months Ended

Jun. 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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SUBSEQUENT EVENTS: (Details) (Subsequent event, USD $)	1 Months Ended
	Jul. 31, 2012 acre
Subsequent event
SUBSEQUENT EVENTS
Area of land	5,600
Principal amount of lease	$ 60,000,000
Lease rent paid	12,000,000
Future installment payments payable	$ 12,000,000
Term of lease over which installment payments will be made	4 years

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COMMITMENTS AND CONTINGENT LIABILITIES: (Tables)

6 Months Ended

Jun. 30, 2012

COMMITMENTS AND CONTINGENT LIABILITIES:

Schedule of future minimum noncancelable lease payments

	Office Leases		Line of Credit		Total
2012	$	537,233	$	—	$	537,233
2013	1,098,709		—		1,098,709
2014	1,085,740		—		1,085,740
2015	1,111,256		—		1,111,256
2016 and thereafter	2,235,743		62,600,000		64,835,743
	$	6,068,681	$	62,600,000	$	68,668,681

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SENIOR SECURED REVOLVING CREDIT FACILITY: (Details) (Revolver, USD $) In Millions, unless otherwise specified			6 Months Ended					6 Months Ended
	Jun. 30, 2012	May 08, 2012	Jun. 30, 2012 LIBOR	Jun. 30, 2012 Bank Prime Rate	Jun. 30, 2012 Minimum	Jun. 30, 2012 Minimum LIBOR	Jun. 30, 2012 Minimum Bank Prime Rate	Jun. 30, 2012 Maximum	Jun. 30, 2012 Maximum LIBOR	Jun. 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
Commitment fees (as a percent)					0.375%			0.50%

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CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
CONSOLIDATED STATEMENTS OF OPERATIONS
General and administrative, stock compensation	$ 795,774	$ 60,000	$ 1,466,338	$ 60,000

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RECENT ACCOUNTING PRONOUNCEMENTS:

6 Months Ended

Jun. 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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COMMITMENTS AND CONTINGENT LIABILITIES: (Details) (USD $)	Jun. 30, 2012
Office leases
2012	$ 537,233
2013	1,098,709
2014	1,085,740
2015	1,111,256
2016 and thereafter	64,835,743
Total	68,668,681
Office Leases
Office leases
2012	537,233
2013	1,098,709
2014	1,085,740
2015	1,111,256
2016 and thereafter	2,235,743
Total	6,068,681
Line of Credit
Office leases
2016 and thereafter	62,600,000
Total	$ 62,600,000

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ACCOUNTS PAYABLE AND ACCRUED EXPENSES: (Tables)

6 Months Ended

Jun. 30, 2012

ACCOUNTS PAYABLE AND ACCRUED EXPENSES:

Schedule of accounts payable and accrued expenses

	2012		2011
Drilling and completion costs	$	53,730,952	$	14,153,449
Accounts payable trade	2,528,046		4,976,979
Ad valorem taxes	190,627		1,781,021
Accrued general and administrative cost	2,494,509		1,713,708
Accrued initial public offering expenses	—		1,258,791
Lease operating expense	2,361,200		2,128,470
Accrued reclamation cost	400,000		400,000
Accrued interest	257,797		17,965
Accrued oil and gas hedging	186,973		353,897
Production taxes and other	2,281,090		284,046
	$	64,431,194	$	27,068,326