Edgar Filing: Bonanza Creek Energy, Inc.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2014

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

For the transition period from to

Commission File Number: 001-35371

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 filerx		Accelerated filero

Non-accelerated filero		Smaller reporting companyo
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o 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. 40,389,592 shares of common stock were outstanding as of May 5, 2014.

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	March 31, 2014			December 31, 2013
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	131,343		$	180,582
Accounts receivable:
Oil and gas sales	66,835			57,485
Joint interest and other	16,287			12,915
Prepaid expenses and other	4,274			1,638
Inventory of oilfield equipment	8,597			10,696
Derivative asset	145			858
Total current assets	227,481			264,174
Property and equipment (successful efforts method), at cost:
Proved properties	1,395,629			1,257,288
Less: accumulated depreciation, depletion and amortization	(264,466		)	(224,848		)
Total proved properties, net	1,131,163			1,032,440
Unproved properties	14,653			45,081
Wells in progress	155,642			110,848
Natural gas plant, net of accumulated depreciation of $6,541 in 2014 and $5,903 in 2013	70,176			71,474
Other property and equipment, net of accumulated depreciation of $3,500 in 2014 and $2,822 in 2013	7,566			7,406
Oil and gas properties held for sale, net of accumulated depreciation, depletion, and amortization of $ - in 2014 and $1,463 in 2013 (note 4)	—			360
Total property and equipment, net	1,379,200			1,267,609

Long-term derivative asset	—			293
Other noncurrent assets	13,463			13,859
Total assets	$	1,620,144		$	1,545,935
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses (note 5)	$	168,161		$	121,665
Oil and gas revenue distribution payable	29,230			36,241
Contractual obligation for land acquisition	12,000			12,000
Derivative liability	11,071			5,320
Total current liabilities	220,462			175,226

Long-term liabilities:
Senior Notes, net of unamortized premium of $8,540 in 2014 and $8,847 in 2013	508,540			508,847
Contractual obligation for land acquisition	22,223			22,033
Ad valorem taxes	24,002			18,867
Derivative liability	997			1,203
Deferred income taxes, net	161,152			152,681
Asset retirement obligations	10,873			11,050
Total liabilities	948,249			889,907

Commitments and contingencies (Note 7)

Stockholders’ equity:
Preferred stock, $.001 par value, 25,000,000 shares authorized, none outstanding	—			—
Common stock, $.001 par value, 225,000,000 shares authorized,40,395,690 and 40,285,919 issued and outstanding in 2014 and 2013, respectively	40			40
Additional paid-in capital	530,088			527,752
Retained earnings	141,767			128,236
Total stockholders’ equity	671,895			656,028
Total liabilities and stockholders’ equity	$	1,620,144		$	1,545,935

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

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Three Months Ended March 31,
	2014			2013
	(in thousands, except per share amounts)
Operating net revenues:
Oil and gas sales	$	127,395		$	78,307
Operating expenses:
Lease operating expenses	17,082			11,131
Severance and ad valorem taxes	10,749			4,812
Exploration	1,083			562
Depreciation, depletion and amortization	41,132			23,363
General and administrative (including $6,797 and $4,378 in 2014 and 2013, respectively, of stock compensation)	23,714			13,166
Total operating expenses	93,760			53,034
Income from operations	33,635			25,273
Other income (expense):
Derivative loss	(8,778		)	(5,116		)
Interest expense	(9,335		)	(1,963		)
Other income	51			137
Total other expense	(18,062		)	(6,942		)
Income from continuing operations before taxes	15,573			18,331
Income tax expense	(5,996		)	(7,058		)
Income from continuing operations	$	9,577		$	11,273
Discontinued operations (Note 4)
Loss from operations associated with oil and gas properties held for sale	(85		)	(27		)
Gain on sale of oil and gas properties	6,514			—
Income tax (expense) benefit	(2,475		)	10
Gain (loss) from discontinued operations	3,954			(17		)
Net income	$	13,531		$	11,256
Comprehensive income	$	13,531		$	11,256
Basic and diluted income per share:
Income from continuing operations	$	0.24		$	0.28
Income (loss) from discontinued operations	$	0.10		$	—
Net income per common share	$	0.34		$	0.28
Basic weighted-average common shares outstanding	39,605,083			39,253,743
Diluted weighted-average common shares outstanding	39,761,738			39,285,215

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

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Three Months Ended March 31,
	2014			2013
	(in thousands)
Cash flows from operating activities:
Net income	$	13,531		$	11,256
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	41,199			23,467
Deferred income taxes	8,471			7,048
Stock-based compensation	6,797			4,378
Amortization of deferred financing costs	562			219
Amortization of premium on senior notes	(307		)	—
Accretion of contractual obligation for land acquisition	190			190
Derivative loss	8,778			5,116
Gain on sale of oil and gas properties	(6,514		)	—
Other	(2		)	73
Changes in current assets and liabilities:
Accounts receivable	(12,721		)	(6,912		)
Prepaid expenses and other assets	(2,637		)	81
Accounts payable and accrued liabilities	20,337			(5,068		)
Settlement of asset retirement obligations	—			(49		)
Net cash provided by operating activities	77,684			39,799
Cash flows from investing activities:
Acquisition of oil and gas properties	(1,202		)	(934		)
Proceeds from Sale of Oil and Gas Properties	6,000			—
Exploration and development of oil and gas properties	(123,835		)	(64,334		)
Natural gas plant capital expenditures	(194		)	(3,275		)
Derivative cash settlements	(2,227		)	(1,507		)
Additions to property and equipment - non oil and gas	(838		)	(1,386		)
Net cash used in investing activities	(122,296		)	(71,436		)
Cash flows from financing activities:
Proceeds from credit facility	—			33,500
Offering costs related to sale of senior subordinated notes	(140		)	—
Payment of employee tax withholdings in exchange for the return of common stock	(4,461		)	(2,908		)
Deferred financing costs	(26		)	(52		)
Net cash (used in) provided by financing activities	(4,627		)	30,540
Net change in cash and cash equivalents	(49,239		)	(1,097		)
Cash and cash equivalents:
Beginning of period	180,582			4,267
End of period	$	131,343		$	3,170
Supplemental cash flow disclosure:
Cash paid for interest	$	464		$	1,469
Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition	$	23,238		$	(5,460	)

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

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE 1 - ORGANIZATION AND BUSINESS

Bonanza Creek Energy, Inc. (the “Company” or “BCEI”) is engaged in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States. Our oil and liquids weighted assets are concentrated primarily in the Wattenberg Field in Colorado (Rocky Mountain region) and the Dorcheat Macedonia Field in southern Arkansas (Mid-Continent region).

NOTE 2 - BASIS OF PRESENTATION

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information. The quarterly financial statements included herein do not necessarily include all of the disclosures as may be required under generally accepted accounting principles for complete financial statements. There has been no material change in the information disclosed in the notes to the consolidated financial statements included in BCEI’s Annual Report on Form 10-K for the year ended December 31, 2013 (“2013 Form 10-K”), except as disclosed herein. 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. The Company evaluated events subsequent to the balance sheet date of March 31, 2014, through the filing date of this report. Certain prior period amounts are reclassified to conform to the current period presentation, when necessary.

Principles of Consolidation

The consolidated balance sheets include the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Bonanza Creek Energy Resources, LLC, Holmes Eastern Company, LLC, Bonanza Creek Energy Upstream LLC, and Bonanza Creek Energy Midstream, LLC. All significant intercompany accounts and transactions have been eliminated.

Significant Accounting Policies

The significant accounting policies followed by the Company were set forth in Note 1 to the 2013 Form 10-K and are supplemented by the notes throughout in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the 2013 Form 10-K.

NOTE 3 - ACQUISITIONS

The Company did not complete any material acquisitions during the three months ended March 31, 2014.

On July 31, 2012, the Company acquired leases to approximately 5,600 net acres in the Wattenberg Field from the State of Colorado, State Board of Land Commissioners. The Company paid approximately $12 million at closing, $12 million on July 31, 2013, and will pay approximately $12 million on July 31st of each of the next three years. These future payments were discounted based on our effective borrowing rate to arrive at the purchase price of $57 million. These future payments are secured by a $36 million letter of credit as of March 31, 2014 and interest will be imputed on the future payments. Following each payment the amount secured by the letter of credit will be amended each year on July 31st to reflect the reduction in obligation.

NOTE 4 - DISCONTINUED OPERATIONS

During June of 2012, the Company began marketing, with an intent to sell, all of its oil and gas properties in California classifying them as assets held for sale. 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 its intent to sell all of its assets in a region qualified as discontinued operations. The Company sold its remaining property during the first quarter of 2014 for approximately $6.0 million and recorded a gain on the sale of oil and gas properties in the amount of $6.5 million. The carrying amounts of the remaining properties included within assets held for sale classified as discontinued operations are presented below.

	As of March 31, 2014		As of December 31, 2013
	(in thousands)
Assets held for sale:
Oil and gas properties, successful efforts method:
Proved properties	$	—	$	1,721
Unproved properties	—		1
Wells in progress	—		101
Total property and equipment	—		1,823
Less accumulated depreciation, depletion and amortization	—		(1,463		)
Net property and equipment	$	—	$	360

The total revenues, expenses, and income associated with the operation of the oil and gas properties held for sale are presented below.

	Three Months Ended March 31,
	2014			2013
	(in thousands)
Net revenues:
Oil and gas sales	$	361		$	438

Operating expenses:
Lease operating expense	366			304
Severance and ad valorem taxes	13
Exploration				57
Depreciation, depletion and amortization	67			104
Total operating expenses	446			465

Loss from operations associated with oil and gas properties held for sale	$	(85	)	$	(27	)

NOTE 5 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses contain the following:

	As of March 31, 2014		As of December 31, 2013
	(in thousands)
Drilling and completion costs	$	104,210	$	80,971
Accounts payable trade	17,207		3,288
Accrued general and administrative cost	11,648		12,720
Lease operating expense	4,574		5,440
Accrued reclamation cost	166		168
Accrued interest	15,491		7,065
Accrued oil and gas derivatives	955		446
Production and ad valorem taxes and other	13,910		11,567
	$	168,161	$	121,665

NOTE 6 — REVOLVING CREDIT FACILITY

The Company’s senior secured revolving Credit Agreement (the “Revolver” or “credit facility”), dated March 29, 2011, as amended, provides for borrowings of up to $600 million. As of March 31, 2014, and through the filing date of this report, the borrowing base under the Revolver was $450 million. The Company elected to limit bank commitments to $330 million while reserving the option to access, at the Company’s request, the full $450 million prior to the next semi-annual redetermination on May 15, 2014. The Revolver is collateralized by substantially all the Company’s assets and matures on September 15, 2018. As of March 31, 2014, and through the filing date of this report, the Company had no outstanding balance under the Revolver with an available borrowing capacity of $414 million after the reduction of the outstanding letter of credit of $36 million.

The Revolver 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 minimum current and debt coverage ratios. The Company was in compliance with all financial and non-financial covenants as of March 31, 2014 and through the filing date of this report.

NOTE 7 - COMMITMENTS AND CONTINGENT LIABILITIES

From time to time, the Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. In accordance with accounting authoritative guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. No claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration or the violation of any rules or regulations. As of the date of this filing, there were no material pending or overtly threatened legal actions against the Company of which it is aware.

Commitments

There have been no material changes from the commitments disclosed in the notes to the Company’s consolidated financial statements included in the 2013 Form 10-K.

NOTE 8 — STOCK-BASED COMPENSATION

Restricted Stock under the Long Term Incentive Plan

The Company grants shares of restricted stock, which represents one share of the Company’s common stock vesting in one-third increments over three years. Shares of restricted stock are valued at the closing price of the Company’s common stock on the grant date and are recognized as general and administrative expense over the vesting period of the award.

Total expense recorded for restricted stock for the three month periods ended March 31, 2014 and 2013, was $6.6 million and $4.4 million, respectively. As of March 31, 2014, unrecognized compensation cost was $21.7 million and will be amortized through 2017.

Performance Stock Units under the Long Term Incentive Plan

The Company grants performance stock units (“PSUs”) to certain officers of the Company. The number of shares of the Company’s common stock that may be issued to settle PSUs range from zero to two times the number of PSUs awarded and is determined based on the Company’s performance over a three-year measurement period. The PSUs granted during 2013 vest in their entirety at the end of the measurement period. The PSUs granted during 2014 vest at the end of each annual measurement period during the performance cycle up to two-thirds of the target number of PSUs that are eligible for vesting (such that an amount equal to 200% of the target number may be earned during the performance cycle of three years). The PSUs will be settled in shares following the end of the three year performance cycle.

Total expense recorded for PSUs for the three month period ended March 31, 2014 was $0.2 million. As of March 31, 2014, there was $3.4 million of total unrecognized compensation expense related to unvested PSUs to be amortized through 2015. There have been no material changes to the outstanding and non-vested PSUs during the quarter ended March 31, 2014.

NOTE 9 - FAIR VALUE MEASUREMENTS

The Company follows fair value measurement authoritative guidance for all assets and liabilities measured at fair value, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A hierarchy for inputs is 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. 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, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

Level 3: Significant inputs to the valuation model are unobservable

Financial assets and liabilities are 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 tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 and December 31, 2013 and their classification within the fair value hierarchy:

	As of March 31, 2014
	Level 1		Level 2		Level 3
	(in thousands)
Derivative assets	$	—	$	—	$	145
Derivative liabilities	$	—	$	3,906	$	8,162

	As of December 31, 2013
	Level 1		Level 2		Level 3
	(in thousands)
Derivative assets	$	—	$	736	$	415
Derivative liabilities	$	—	$	1,741	$	4,782

Derivatives

Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, 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. Presently, all of our derivative arrangements are concentrated with five counterparties all of which are lenders under the Company’s Revolver.

The following table reflects the activity for the commodity derivatives measured at fair value using Level 3 inputs during the quarter ended March 31, 2014:

	Derivative Asset			Derivative Liability
	(in thousands)
Beginning balance	$	415		$	4,782
Net (decrease) increase in fair value(1)	478			3,774
Net settlement(1)	(879		)	(882		)
New derivatives	131			488
Transfers in (out) of Level 3	—			—
Ending balance	$	145		$	8,162

(1) Net (decrease) increase in fair value and net settlements are a component of the derivative gain (loss) line item in the accompanying statements of operations.

Proved Oil and Gas Properties

Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs exceed the sum of the undiscounted cash flows. The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts selected by the Company’s management. The calculation of the discount rate is a significant management estimate based on the best information available and estimated to be 10%. Management believes that the discount rate is representative of current market conditions and reflects the following factors: estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based

on the NYMEX strip pricing, adjusted for basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. There were no proved properties measured at fair value at March 31, 2014 or December 31, 2013.

Unproved Oil and Gas Properties

Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses Level 3 inputs and the income valuation technique, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, and estimated reserve values. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company uses the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. There were no unproved properties measured at fair value as of March 31, 2014 or December 31, 2013.

Asset Retirement Obligation

The Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Upon completion of wells and natural gas plants, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. There were no asset retirement obligations measured at fair value at March 31, 2014 or December 31, 2013.

Long-term Debt

As of March 31, 2014, the Company had $500 million of outstanding 6.75% Senior Notes (the “Senior Notes”). The Senior Notes are recorded at cost net of the unamortized premium on the accompanying balance sheets at $508.5 million and $508.8 million as of March 31, 2014 and December 31, 2013, respectively. The fair value of the Senior Notes as of March 31, 2014 and December 31, 2013 was $526.0 million and $527.5 million, respectively, measured using Level 1 inputs based on a secondary market trading price. The carrying value of the Company’s credit facility approximates fair value, as the applicable interest rates are floating.

NOTE 10 — DERIVATIVES

The Company enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The Company’s derivatives include swaps and collar arrangements for oil and gas and none of the derivative instruments qualify as having hedging relationships.

As of March 31, 2014, the Company had the following derivative commodity contracts in place:

Settlement Period	Derivative Instrument	Total Volumes (Bbls/MMBtu per day)	Average Fixed Price		Average Short Floor Price		Average Floor Price		Average Ceiling Price		Fair Market Value of Asset (Liability)
											(in thousands)
Oil
2Q 2014	Swap	4,126	$	96.20							(1,599		)
3Q 2014	Swap	3,870	$	93.04							(1,623		)
4Q 2014	Swap	3,870	$	93.04							(683		)
2Q 2014	Collar	4,846					$	86.55	$	96.72	(2,039		)
3Q 2014	Collar	4,326					$	86.16	$	96.57	(1,464		)
4Q 2014	Collar	4,326					$	86.16	$	96.57	(824		)
2Q 2014	3-Way Collar	2,000			$	65.00	$	87.68	$	99.75	(442		)
3Q 2014	3-Way Collar	2,000			$	65.00	$	87.68	$	99.75	(339		)
4Q 2014	3-Way Collar	2,000			$	65.00	$	87.68	$	99.75	(96		)
1Q 2015	3-Way Collar	5,500			$	67.27	$	83.75	$	95.19	(1,137		)
2Q 2015	3-Way Collar	4,500			$	66.67	$	83.33	$	94.12	(688		)
3Q 2015	3-Way Collar	4,500			$	66.67	$	83.33	$	94.12	(342		)
4Q 2015	3-Way Collar	4,500			$	66.67	$	83.33	$	94.12	(84		)
											$	(11,360	)
Gas
2Q 2014	3-Way Collar	30,000			$	3.63	$	4.21	$	4.81	$	85
3Q 2014	3-Way Collar	30,000			$	3.63	$	4.21	$	4.81	$	(46	)
4Q 2014	3-Way Collar	30,000			$	3.63	$	4.21	$	4.81	$	(302	)
1Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	(417	)
2Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	80
3Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	52
4Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	(15	)
											$	(563	)

Total											$	(11,923	)

As of the date of filing we had the following economic derivatives in place, which settle monthly:

Settlement Period	Derivative Instrument	Total Volumes (Bbls/MMBtu per day)	Average Fixed Price		Average Short Floor Price		Average Floor Price		Average Ceiling Price
Oil
2Q 2014	Swap	4,126	$	96.20
3Q 2014	Swap	3,870	$	93.04
4Q 2014	Swap	4,370	$	93.47
1Q 2015	Swap	2,000	$	92.22
2Q 2015	Swap	1,000	$	90.40
3Q 2015	Swap	1,000	$	90.40
4Q 2015	Swap	1,000	$	90.40
2Q 2014	Collar	4,846					$	86.55	$	96.72
3Q 2014	Collar	4,326					$	86.16	$	96.57
4Q 2014	Collar	4,326					$	86.16	$	96.57
2Q 2014	3-Way Collar	2,000			$	65.00	$	87.68	$	99.75
3Q 2014	3-Way Collar	2,000			$	65.00	$	87.68	$	99.75
4Q 2014	3-Way Collar	2,000			$	65.00	$	87.68	$	99.75
1Q 2015	3-Way Collar	5,500			$	67.27	$	83.75	$	95.19
2Q 2015	3-Way Collar	4,500			$	66.67	$	83.33	$	94.12
3Q 2015	3-Way Collar	4,500			$	66.67	$	83.33	$	94.12
4Q 2015	3-Way Collar	4,500			$	66.67	$	83.33	$	94.12
Gas
2Q 2014	3-Way Collar	30,000			$	3.63	$	4.21	$	4.81
3Q 2014	3-Way Collar	30,000			$	3.63	$	4.21	$	4.81
4Q 2014	3-Way Collar	30,000			$	3.63	$	4.21	$	4.81
1Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75
2Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75
3Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75
4Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75

Derivative Assets and Liabilities Fair Value

The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities.

The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of March 31, 2014 and December 31, 2013:

	As of March 31, 2014
	Balance Sheet Location	Fair Value
		(in thousands)
Derivative Assets:
Commodity contracts	Current assets	$	145
Commodity contracts	Noncurrent assets	—
Derivative Liabilities:
Commodity contracts	Current liabilities	(11,071		)
Commodity contracts	Long-term liabilities	(997		)
Total net derivative liability		$	(11,923	)

	As of December 31, 2013
	Balance Sheet Location	Fair Value
		(in thousands)
Derivative Assets:
Commodity contracts	Current assets	$	858
Commodity contracts	Noncurrent assets	293
Derivative Liabilities:
Commodity contracts	Current liabilities	(5,320		)
Commodity contracts	Long-term liabilities	(1,203		)
Total net derivative liability		$	(5,372	)

The following table summarizes the components of the derivative gain (loss) presented on the accompanying statements of operations:

	For the Three Months Ended March 31,
	2014			2013
	(in thousands)
Derivative cash settlement gain (loss):
Oil contracts	$	(1,699	)	$	(1,651	)
Gas contracts	(528		)	144
Total derivative cash settlement (loss)(1)	$	(2,227	)	$	(1,507	)

Change in fair value gain (loss)	$	(6,551	)	$	(3,609	)

Total derivative gain (loss)(2)	$	(8,778	)	$	(5,116	)

(1) Derivative cash settlement gain (loss) is reported in the derivative cash settlements line item on the accompanying statements of cash flows within the net cash used in investing activities.

(2) Total derivative gain (loss) is reported in the derivative gain (loss) line item on the accompanying statements of cash flows within the net cash provided by operating activities.

NOTE 11 — EARNINGS PER SHARE

The Company issues shares of restricted stock entitling the holders to receive non-forfeitable dividends, if and when, the Company were to declare a dividend, before vesting, thus making the awards participating securities. The awards are included in the calculation of earnings per share under the two-class method. The two-class method allocates earnings for the period between common shareholders and unvested participating shareholders.

The following table sets forth the calculation of earnings per basic and diluted shares from continuing and discontinued operations for the three-month periods ended March 31, 2014 and 2013:

	For the Three Months Ended March 31,
	2014		2013
	(in thousands, except per share amounts)
Income from continuing operations:
Income from continuing operations	$	9,577	$	11,273
Less: undistributed earnings to unvested restricted stock	181		242
Undistributed earnings to common shareholders	9,396		11,031
Basic income per common share from continuing operations	$	0.24	$	0.28
Diluted income per common share from continuing operations	$	0.24	$	0.28

Income (loss) from discontinued operations:
Income (loss) from discontinued operations	$	3,954	$	(17	)
Less: undistributed earnings to unvested restricted stock	75		(1		)
Undistributed earnings (loss) to common shareholders	3,879		(16		)
Basic loss per common share from discontinued operations	$	0.10	$	0.00
Diluted loss per common share from discontinued operations	$	0.10	$	0.00

Net income:
Net income	$	13,531	$	11,256
Less: undistributed earnings to unvested restricted stock	256		241
Undistributed earnings to common shareholders	13,275		11,015
Basic net income per common share	$	0.34	$	0.28
Diluted net income per common share	$	0.34	$	0.28

Weighted-average shares outstanding - basic	39,605,083		39,253,743
Add: dilutive effect of contingent PSUs	156,655		31,472
Weighted-average shares outstanding - diluted	39,761,738		39,285,215

The Company had no anti-dilutive shares for the quarters ended March 31, 2014 and 2013.

NOTE 12 - 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. During the three month periods ended March 31, 2014 and 2013 the effective tax rate was 38.5% and 38.5%, respectively.

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 has not taken any uncertain tax positions and has no valuation allowances.

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, 2013 (the “2013 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”).

Executive Summary

Bonanza Creek Energy, Inc. (“BCEI” or, together with our consolidated subsidiaries, the “Company,” “we,” “us,” or “our”) is a Denver-based exploration and production company focused on the extraction of oil and associated liquids-rich natural gas in the United States. Our predecessors were founded in 1999 and we completed our initial public offering in December 2011. Our shares of common stock are listed for trading on the NYSE under the symbol “BCEI.”

Despite the uncertainty surrounding the global economy and volatility in commodity prices, we believe the economic returns and organic growth generated by our portfolio of oil and gas assets positions us well moving forward. Our operations are focused in the Wattenberg Field in Colorado (Rocky Mountain region) and the Dorcheat Macedonia Field in southern Arkansas (Mid-Continent region). The low risk, oil-weighted production profile of our Arkansas assets provides a strong cash flow base from which to develop our Wattenberg Field assets, principally the Niobrara and Codell formations in Colorado. Our corporate strategy is to create shareholder value by increasing production in our current assets, while opportunistically seeking strategic acquisitions in our core areas or other high return basins across the United States where we can apply our technical competencies of horizontal drilling and

fracture stimulation. We maintain a high working interest in our properties, which allows us to control the pace and magnitude of our capital spending program.

First Quarter 2014 Financial and Operating Highlights

Our financial results for the quarter ended March 31, 2014 included:

· Net income of $13.5 million (including approximately $9.6 million from continuing operations), as compared with $11.3 million (including approximately $11.3 million from continuing operations) for the first quarter of 2013;

· Cash flows provided by operating activities of $77.7 million, as compared with $39.8 million in the first quarter of 2013;

· Capital expenditures of $152 million, as compared with $61.4 million in the first quarter of 2013; and

· Total liquidity of $545.3 million at March 31, 2014, consisting of a period-end cash balance plus funds available under our senior secured revolving Credit Agreement (the “Revolver” or “credit facility”), as compared with $88.7 million at March 31, 2013.

Operational highlights for the first quarter of 2014 included the following:

· Increased production from continuing operations by 60% to 1,773.1 MBoe in the first quarter of 2014 from 1,107.6 MBoe in the first quarter of 2013, with oil and NGL production representing 71% of total production; and

· Decreased average unit production costs from continuing operations by 4% to $9.63 per Boe in the first quarter of 2014 from $10.05 per Boe in the first quarter of 2013.

Outlook for 2014

Because the global economic outlook and commodity price environment are uncertain, we have planned a flexible capital spending program. We estimate our total capital expenditures for 2014 to be approximately $575 million to $625 million, allocated approximately 87% to the Wattenberg Field and 13% to southern Arkansas. Actual capital expenditures may fluctuate materially based on, among other things, market conditions, the success of our drilling results as the year progresses and changes in the borrowing base under our Revolver. This capital investment is expected to produce average production volumes of 23,000 Boe/d to 25,000 Boe/d in 2014, while maintaining a strong oil and liquids profile.

Results for Continuing Operations

Three Months Ended March 31, 2014 Compared To Three Months Ended March 31, 2013

The following table summarizes our revenues, sales volumes, and average sales prices for the periods indicated:

	Three Months Ended March 31,
	2014		2013		Change			Percent Change
	(In thousands, except percentages)
Revenues:
Crude oil sales	$	103,747	$	65,677	$	38,070		58	%
Natural gas sales	18,515		8,580		9,935			116	%
Natural gas liquids sales	5,126		3,989		1,137			29	%
CO2 sales	7		61		(54		)	(89	)%
Product revenue	$	127,395	$	78,307	$	49,088		63	%

Sales volumes:
Crude oil (MBbls)	1,164.2		725.2		439.0			61	%
Natural gas (MMcf)	3,089.2		1,846.1		1,243.1			67	%
Natural gas liquids (MBbls)	94.0		74.7		19.3			26	%
Crude oil equivalent (MBoe)(1)	1,773.1		1,107.6		665.5			60	%

Average Sales Prices (before derivatives)(2):
Crude oil (per Bbl)	$	89.11	$	90.56	$	(1.45	)	(2	)%
Natural gas (per Mcf)	5.99		4.65		1.34			29	%
Natural gas liquids (per Bbl)	54.53		53.40		1.13			2	%
Crude oil equivalent (per Boe)(1)	71.85		70.64		1.21			2	%

Average Sales Prices (after derivatives)(2):
Crude oil (per Bbl)	$	87.65	$	88.28	$	(.63	)	(1	)%
Natural gas (per Mcf)	5.82		4.73		1.09			23	%
Natural gas liquids (per Bbl)	54.53		53.40		1.13			2	%
Crude oil equivalent (per Boe)(1)	70.59		69.29		1.30			2	%

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

(2) The derivatives economically hedge the price we receive for crude oil and natural gas.

Revenues increased by 63%, to $127.4 million for the three months ended March 31, 2014 compared to $78.3 million for the three months ended March 31, 2013. Oil, natural gas, and natural gas liquids production increased 61%, 67%, and 26%, respectively, during the three months ended March 31, 2014, as compared to the three months ended March 31, 2013. The increased volumes are a direct result of the $447.1 million expended for drilling and completion activities during the year ended December 31, 2013, and the $152 million expended for such activities during the three months ended March 31, 2014. During the period from January 1, 2013 through March 31, 2014, we completed 97 gross (86.5 net) wells in the Rocky Mountain region and 53 gross (42.5 net) wells in the Mid-Continent region. Oil volumes increased by 61% in the three months ended March 31, 2014, but were offset by a sales price decline of 2% from $90.56 per barrel to $89.11 per barrel for the three month period, which accounted for a $38.1 million increase in revenues. Increased natural gas volumes and prices of 67% and 29%, respectively, for the three month period ended March 31, 2014 compared to the comparable period in the prior year accounted for $9.9 million of the increase in natural gas revenues. Natural gas liquids volumes increased by 26% in the three months ended March 31, 2014, along with a sales price increase of 2% from $53.40 per barrel to $54.53 per barrel for these three month periods which accounted for the $1.1 million increase in revenues. Our Wattenberg Field natural gas is sold as wet gas without processing into dry gas and NGLs, and therefore, sells at a premium due to its high BTU content.

The following table summarizes our operating expenses and per Boe data for the periods indicated:

	Three Months Ended March 31,
	2014		2013		Change			Percent Change
	(In thousands, except percentages)
Expenses:
Lease operating expense	$	17,082	$	11,131	$	5,951		53	%
Severance and ad valorem taxes	10,749		4,812		5,937			123	%
Exploration	1,083		562		521			93	%
Depreciation, depletion and amortization	41,132		23,363		17,769			76	%
General and administrative	23,714		13,166		10,548			80	%
Operating expenses	$	93,760	$	53,034	$	40,726		77	%

Expenses per Boe:
Lease operating	$	9.63	$	10.05	$	(.42	)	(4	)%
Severance and ad valorem taxes	6.06		4.35		1.71			39	%
Exploration	0.61		0.51		.10			20	%
Depreciation, depletion and amortization	23.20		21.09		2.11			10	%
General and administrative	13.37		11.89		1.48			12	%
Operating expenses	$	52.87	$	47.89	$	4.98		10	%

Lease Operating Expense. Our lease operating expenses increased $6.0 million, or 53%, to $17.1 million for the three months ended March 31, 2014 from $11.1 million for the three months ended March 31, 2013 and decreased on a per barrel of oil equivalent basis from $10.05 per Boe to $9.63 per Boe. The aggregate increase in lease operating expense was related to increased production volumes of 60% attributable to our drilling program. During the quarter ended March 31, 2014, three of the largest components of lease operating expense were well servicing, compression, and pumping which increased $3.5 million, $0.9 million, and $1.1 million, respectively, over the comparable period in 2013. Gas plant operating expense, which is a component of lease operating expense, increased $0.8 million, or 31%, to $3.4 million for the three month period ended March 31, 2014 from $2.6 million for the three month period ended March 31, 2013. This increase was due to the Dorcheat Gas Plant commencing service in February

of 2013. Additionally, routine gas plant maintenance in the first quarter of 2014 resulted in increased labor costs of $0.4 million and repairs and maintenance cost increase of $0.4 million. The decrease in lease operating expense on an equivalent basis was primarily related to higher production from our lower cost horizontal wells in the Wattenberg Field.

Severance and ad valorem taxes. Our severance and ad valorem taxes increased $5.9 million, or 123%, to $10.7 million for the three months ended March 31, 2014 from $4.8 million for the three months ended March 31, 2013. The increase was primarily related to a 60% increase in production volumes during the three months ended March 31, 2014 as compared to the three months ended March 31, 2013 and a decrease in ad valorem tax credits associated with our vertical wells in Colorado.

General and administrative. Our general and administrative expense increased $10.5 million, or 80%, to $23.7 million for the three months ended March 31, 2014 from $13.2 million for the three months ended March 31, 2013 and increased on an equivalent basis to $13.37 per Boe from $11.89 per Boe. During the three months ended March 31, 2014, wages and benefits, stock-based compensation, and professional service fees were $3.2 million, $2.4 million, and $1.1 million higher, respectively, than the same period in 2013. The increase in wages and benefits is due to an increase in headcount as a result of our accelerated drilling program between the three month periods ended March 31, 2014 and 2013. The majority of the per Boe increase to general and adminstiratve expense was related to an executive departure which resulted in charges for cash severance and stock-based compensation of $3.6 million and $3.9 million respectively.

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expense increased $17.8 million, or 76%, to $41.1 million for the three months ended March 31, 2014 from $23.4 million for the three months ended March 31, 2013. Our depreciation, depletion and amortization expense per Boe increased $2.11, or 10% to $23.20 for the three months ended March 31, 2014 as compared to $21.09 for the three months ended March 31, 2013. This increase was primarily the result of a significant increase in productive assets with a proved reserve rate increase of 14% period over period and a proved developed reserve rate increase of 2% period over period.

Exploration. Our exploration expense increased $0.5 million to $1.1 million for the three months ended March 31, 2014 from $0.6 million in the three months ended March 31, 2013. During the three months ended March 31, 2014, we incurred a $1.0 million of dry hole charges related to the State Antelope 34-24, which was a vertical well in the Wattenberg Field drilled to test the Lyons formation.

Derivative gain (loss). Our derivative loss increased $3.7 million to $8.8 million for the three month period ended March 31, 2014 from a $5.1 million loss for the comparable period in 2013. The loss incurred was primarily the result of realized prices being greater than the contract prices. Please refer to Note 10 — Derivatives above for additional discussion.

Interest expense. Our interest expense increased $7.3 million, or 376%, to $9.3 million for the three months ended March 31, 2014 from $2.0 million for the three months ended March 31, 2013. The increase for the three month period ended March 31, 2014 is primarily due to the issuance of $500 million in Senior Notes which occurred after the first quarter of 2013. Interest expense on the Senior Notes for the three month period ended March 31, 2014 was $8.5 million. Average debt outstanding for the three months ended March 31, 2014 was $500 million as compared to $181.8 million for the comparable period in 2013.

Income tax expense. Our estimate for federal and state income taxes for the three months ended March 31, 2014 was $6.0 million from continuing operations as compared to $7.1 million for the three months ended March 31, 2013. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. Our effective tax rate for the three month periods ended March 31, 2014 and 2013 was 38.5%, which differs from the U.S. statutory income tax rate primarily due to the effects of state income taxes.

Results for Discontinued Operations

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

The majority of these properties were sold in 2012, and the operating results before income taxes for our California properties for the three months ended March 31, 2014 were net revenues of $0.36 million, and operating expenses of $0.45 million, as compared to net revenues of $0.44 millon, and operating expenses of $0.47 million for the comparable period in 2013. Sales volumes for the three month periods ended March 31, 2014 and 2013 were 40 Boe/d and 49 Boe/d, respectively. On March 21, 2014, the remaining oil & gas property, which was the Midway Sunset Field, sold for approximately $6.0 million. The gain on the sale was approximately $6.5 million. Please refer to Note 4 — Discontinued Operations for additional discussion

Liquidity and Capital Resources

We fund our operations, capital expenditures and working capital requirements with cash flows from our operating activities and borrowings under our revolving credit facility. Periodically, we access debt and capital markets and sell non-core properties to provide additional liquidity.

We believe that our cash on hand, cash flow from operating activities and availability under our revolving credit facility will be sufficient to fund our planned capital expenditures and operating expenses and comply with our debt covenants for at least the next 12 months. To the extent actual operating results differ from our anticipated results; our liquidity could be adversely affected.

Our revolving credit facility has a $450 million borrowing base. In November 2013, the Company elected to limit bank commitments to $330 million while reserving the option to access, at the Company’s request, the full $450 million. As of March 31, 2014, we had nil outstanding on our credit facility, $36 million of letters of credit issued, and $414 million available borrowing capacity. Our weighted-average interest rate (excluding amortization of deferred financing costs and the accretion of our contractual obligation for land acquisition) on borrowings from our credit facility was 3.46% for the three months ended March 31, 2013. For the three months ended March 31, 2014 our weighted-average interest rate was nil and our commitment fees were $0.5 million.

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. Please see Item 3. Quantitative and Qualitative Disclosures on Market Risks below and Note 10 — Derivatives above for additional discussion.

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

	Three Months Ended March 31,
	2014			2013
	(in thousands)
Net cash provided by operating activities	$	77,684		$	39,799
Net cash used in investing activities	(122,296		)	(71,436		)
Net cash used in financing activities	(4,627		)	30,540
Cash and cash equivalents	131,343			3,170
Acquisitions of oil and gas properties	1,202			934
Exploration and development of oil and gas properties and investment in gas processing facility, and obligation on land acquisition	124,029			67,609

Cash flows provided by operating activities

During the three month period ended March 31, 2014, we generated $77.7 million of cash provided by operating activities, an increase of $37.9 million from the comparable period in 2013. The increase in cash flows from operating activities resulted primarily from an increase in production of 60% compounded by a 2% increase in realized sales prices on an equivalent basis. These positive factors were partially offset by increased lease operating expense, production taxes, cash portion of general and administrative expense, and cash portion of interest expense during the three month period ended March 31, 2014 as compared to the three month period ended March 31, 2013. See Results for Continuing Operations above for more information on the factors driving these changes.

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 three months ended March 31, 2014 increased $50.9 million inclusive of $6.0 million in proceeds received from the sale of the Midway Sunset property, compared to the same period in 2013. For the three months ended March 31, 2014, cash used for the acquisition of oil and gas properties was $1.2 million, and cash used for the development of oil and natural gas properties (including cash used for natural gas plant capital expenditures) was $124 million. For the three months ended March 31, 2013, cash used for the acquisition of oil and gas properties was $0.9 million, and cash used for the development of oil and natural gas properties (including cash used for natural gas plant capital expenditures) was $67.6 million.

Cash provided by financing activities

Net cash used for financing activities for the three months ended March 31, 2014 decreased $35.1 million, compared to the same period in 2013. The decrease is primarily due to the company’s ability to finance its operations from remaining funds related to the $500 million in outstanding Senior Notes that were sold during the second and fourth quarters of 2013.

New Accounting Pronouncements

Please refer to Note 2 — Basis of Presentation under Part I, Item 1 of this Report for any recently issued or adopted accounting standards.

Critical Accounting Policies and Estimates

Information regarding our critical accounting policies and estimates is contained in Item 7 of our 2013 Annual Report.

Effects of Inflation and Pricing

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 three month periods ended March 31, 2014 and 2013. 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. Material changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base calculations, depletion expense, impairment assessments of oil and gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

Off-Balance Sheet Arrangements

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

Cautionary Note Regarding Forward-Looking Statements

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. When used in this Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements include statements related to, among other things:

· reserves estimates;

· estimated production for 2014;

· amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;

· ability to modify future capital expenditures;

· the Wattenberg Field being the most prospective area of the Niobrara formation and the Dorcheat Macedonia Field being a primary focus in the Mid-Continent region;

· compliance with debt covenants;

· ability to satisfy obligations related to ongoing operations;

· compliance with government regulations;

· adequacy of gathering systems and impact from the lack of available gathering systems and processing facilities in certain areas;

· natural gas, oil and NGL prices and factors affecting the volatility of such prices;

· impact of lower commodity prices;

· the ability to use derivative instruments to manage commodity price risk;

· plans to drill or participate in wells including the intent to focus in specific areas or formations;

· loss of any purchaser of our products;

· our estimated revenues and losses;

· the timing and success of specific projects;

· intentions with respect to acquisitions and divestitures;

· intentions with respect to working interest percentages;

· management and technical team;

· outcomes and effects of litigation, claims and disputes;

· our business strategy;

· our ability to replace oil and natural gas reserves;

· impact of recently issued accounting pronouncements;

· our financial position;

· our cash flow and liquidity; and

· other statements concerning our operations, economic performance and financial condition.

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. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. 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. Actual results could differ materially from those expressed or implied in the forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to, the following:

· the risk factors discussed in Part I, Item 1A of our 2013 Annual Report;

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

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

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

· ability of our customers to meet their obligations to us;

· 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 local, state, and federal regulatory or legislative actions (including additional taxes and changes in environmental regulation);

· environmental risks;

· seasonal weather conditions and lease stipulations;

· drilling and operating risks, including the risks associated with the employment of horizontal drilling techniques;

· ability to acquire adequate supplies of water for drilling and completion operations;

· availability of oilfield equipment, services and personnel;

· exploration and development risks;

· competition in the oil and natural gas industry;

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

· risks related to our derivative instruments;

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

· ability to maintain effective internal controls;

· access to adequate gathering systems and pipeline take-away capacity to provide adequate infrastructure for the products of 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 and other risks associated with perfecting title for mineral rights in some of our properties;

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

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

All forward-looking statements speak only as of the date of this Report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that may cause our actual results to differ materially from our expectations under Item 1A, Risk Factors, and Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and elsewhere in this Report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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 effect 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.

Commodity Derivative Contracts

Our primary commodity risk management objective is to reduce volatility in our cash flows. We enter into commodity derivative contracts for oil and natural gas using NYMEX futures or over-the-counter derivative financial instruments with counterparties who we believe are well-capitalized counterparties and 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. In addition, 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 derivative arrangements are concentrated with five counterparties, all of which are lenders under our credit facility. If a 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 15 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 derivative settlement and payment for revenues earned.

Please refer to Note 10 — Derivatives in Part I, Item 1of this Report for summary derivative activity tables.

Interest Rates

As of March 31, 2014, and through the filing date of this Report, we had no outstanding borrowings under our credit facility, which is subject to floating market rates of interest. Borrowings under our credit facility bear interest at a fluctuating rate that is tied to an adjusted base rate or LIBOR, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow

Customer Credit Risk

We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history and financial resources of our customers, but we do not require our customers to post collateral.

Marketability of Our Production

The marketability of our production from the Mid-Continent and Rocky Mountain regions depends in part upon the availability, proximity and capacity of third-party refineries, access to regional trucking, pipeline and rail infrastructure, natural gas gathering systems and processing facilities. We deliver crude oil and natural gas produced from these areas through trucking services, pipelines and rail facilities that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.

A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow.

Currently, there are no natural gas pipeline systems that service wells in the North Park Basin, which is prospective for the Niobrara shale. In addition, we are not aware of any plans to construct a facility necessary to process natural gas produced from this Basin. If neither we nor a third party constructs the required pipeline system and processing facility, we may not be able to fully test or develop our resources in the North Park Basin.

There have been no material changes to the interest rate risk analysis or oil and gas price sensitivity analysis disclosed in our 2013 Annual Report.

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 March 31, 2014. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of March 31, 2014, 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 March 31, 2014 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 that of which we are aware.

Item 1A. Risk Factors.

Our business faces many risks. Any of the risk factors discussed in this 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. For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our 2013 Annual Report. During the three months ended March 31, 2014, there have been no material changes to our risk factors from those described in our 2013 Annual Report.

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

Unregistered sales of securities. There were no sales of unregistered equity securities during the three month period ended March 31, 2014.

Issuer purchases of equity securities. The following table contains information about our acquisition of equity securities during the three month period ended March 31, 2014:

	Total Number of Shares Purchased(1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Be Purchased Under Plans or Programs

January 1, 2014 — January 31, 2014	1,549	$	43.48	—	—
February 1, 2014 — February 28, 2014	75,356	$	44.21	—	—
March 1, 2014 — March 31, 2014	16,862	$	46.67	—	—

Total	93,767	$	46.10	—	—

(1) Represent shares that employees surrendered back to us that equaled in value the amount of taxes needed for payroll tax withholding obligations upon the vesting of restricted stock awards. These repurchases were not part of a publicly announced program or plan to repurchase shares of our common stock, nor do we have a publicly announced program or plan to repurchase shares of our common stock.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.

Item 6. Exhibits.

Exhibit No.		Description of Exhibit

10.1		Severance Agreement, effective January 31, 2014, by and between Michael R. Starzer and the Company.

10.2		Form of Performance Share Agreement for 2014 performance share unit grants.

10.3		Employment Letter Agreement effective March 21, 2014 between the Company and Wade E. Jaques (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 24, 2014).

31.1		Certification of the Principal Executive Officer pursuant to Rule 13a-14(a).

31.2		Certification of the Principal Financial Officer pursuant to Rule 13a-14(a).

32.1		Certification of the Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

32.2		Certification of the Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).

101		The following materials from the Bonanza Creek Energy, Inc. Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, 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.

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:	May 9, 2014	By:	/s/ Marvin M. Chronister
			Marvin M. Chronister
			Interim President and Chief Executive Officer
			(principal executive officer)


		By:	/s/ William J. Cassidy
			William J. Cassidy
			Executive Vice President and Chief Financial Officer
			(principal financial officer)


		By:	/s/ Wade E. Jaques
			Wade E. Jaques
			Vice President, Chief Accounting Officer
			(principal accounting officer)