UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2013

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 filer o		Accelerated filer x

Non-accelerated filer o		Smaller reporting company o
(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. 40,279,049 shares of common stock were outstanding as of September 30, 2013.

Table of Contents

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(unaudited)

	September 30, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	17,368,896		$	4,267,667
Accounts receivable:
Oil and gas sales	62,937,148			38,600,436
Joint interest and other	13,228,686			5,484,620
Prepaid expenses and other	2,305,269			3,031,815
Inventory of oilfield equipment	5,389,949			1,740,934
Derivative asset	620,446			2,178,064
Total current assets	101,850,394			55,303,536
OIL AND GAS PROPERTIES—using the successful efforts method of accounting:
Proved properties	1,155,502,451			811,000,239
Unproved properties	44,444,030			72,928,364
Wells in progress	86,499,729			75,031,806
	1,286,446,210			958,960,409
Less: accumulated depreciation, depletion and amortization	(175,678,611		)	(89,669,725		)
	1,110,767,599			869,290,684
NATURAL GAS PLANT	75,301,626			73,087,603
Less: accumulated depreciation	(5,269,290		)	(3,403,817		)
	70,032,336			69,683,786
OTHER PROPERTY AND EQUIPMENT	8,784,996			5,089,795
Less: accumulated depreciation	(2,237,696		)	(890,093		)
	6,547,300			4,199,702
OIL AND GAS PROPERTIES HELD FOR SALE, LESS ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION	441,595			582,388
LONG-TERM DERIVATIVE ASSET	480,874			—
OTHER ASSETS, net	9,651,725			3,429,711
TOTAL ASSETS	$	1,299,771,823		$	1,002,489,807
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued expenses	$	96,917,401		$	72,850,272
Oil and gas revenue distribution payable	27,292,365			12,552,655
Contractual obligation for land acquisition	11,999,877			11,999,877
Derivative liability	9,613,257			5,200,202
Total current liabilities	145,822,900			102,603,006
LONG-TERM LIABILITIES:
Long-term debt	338,500,000			158,000,000
Contractual obligation for land acquisition	21,842,731			33,271,631
Ad valorem taxes	18,398,927			11,179,370
Derivative liability	294,440			1,208,106
Deferred income taxes, net	137,778,212			110,376,606
Asset retirement obligations	8,652,597			7,333,584
TOTAL LIABILITIES	671,289,807			423,972,303
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, 40,279,049 and 40,115,536 issued and outstanding, respectively	40,279			40,116
Additional paid-in capital	525,637,560			519,425,356
Retained earnings	102,804,177			59,052,032
Total stockholders’ equity	628,482,016			578,517,504
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,299,771,823		$	1,002,489,807

See accompanying notes to these consolidated financial statements.

Table of Contents

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
NET REVENUES:
Oil and gas sales	$	125,973,199		$	58,327,823		$	288,797,684		$	157,613,348
OPERATING EXPENSES:
Lease operating	12,957,541			8,444,403			36,986,307			22,506,131
Severance and ad valorem taxes	8,085,512			3,021,860			18,250,331			9,387,094
Exploration	2,099,415			6,359,222			3,524,111			9,563,876
Depreciation, depletion and amortization	36,750,003			17,715,763			89,629,794			41,751,296
Impairment of proved properties	—			268,500			—			268,500
General and administrative (including $2,652,476 $1,445,910, $9,715,764, and $2,912,248, respectively, of stock-based compensation)	13,811,237			9,335,266			40,260,147			22,410,369
Total operating expenses	73,703,708			45,145,014			188,650,690			105,887,266
INCOME FROM OPERATIONS	52,269,491			13,182,809			100,146,994			51,726,082
OTHER INCOME (EXPENSE):
Other (loss)	(53,525		)	(90,640		)	(3,167		)	(82,930		)
Interest expense	(6,180,497		)	(1,125,634		)	(14,012,990		)	(2,341,843		)
Unrealized gain (loss) in fair value of commodity derivatives	(10,016,608		)	(9,007,034		)	(4,576,133		)	2,985,356
Realized (loss) on settled commodity derivatives	(6,872,437		)	(92,812		)	(9,866,372		)	(1,173,619		)
Total other (loss)	(23,123,067		)	(10,316,120		)	(28,458,662		)	(613,036		)
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES	29,146,424			2,866,689			71,688,332			51,113,046
Income tax expense	(11,221,296		)	(1,222,450		)	(27,607,420		)	(19,797,360		)
INCOME FROM CONTINUING OPERATIONS	$	17,925,128		$	1,644,239		$	44,080,912		$	31,315,686
DISCONTINUED OPERATIONS (Note 3)
(Loss) from operations associated with oil and gas properties held for sale	(233,584		)	(1,410,595		)	(534,581		)	(791,394		)
Gain on sale of oil and gas properties	—			4,279,998			—			4,279,998
Income tax (expense) benefit	89,877			(1,092,755		)	205,814			(1,331,147		)
Income (loss) associated with oil and gas properties held for sale	(143,707		)	1,776,648			(328,767		)	2,157,457
NET INCOME	$	17,781,421		$	3,420,887		$	43,752,145		$	33,473,143
COMPREHENSIVE INCOME	$	17,781,421		$	3,420,887		$	43,752,145		$	33,473,143
BASIC AND DILUTED INCOME PER SHARE
Income from continuing operations	$	0.44		$	0.04		$	1.10		$	0.79
Income (loss) from discontinued operations	$	—		$	0.05		$	(0.01	)	$	0.06
Net income per common share	$	0.44		$	0.09		$	1.09		$	0.85
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK
Basic (Note 10)	40,266,516			39,477,101			40,209,752			39,476,133
Diluted (Note 10)	40,321,088			39,477,101			40,266,031			39,476,133

See accompanying notes to these consolidated financial statements.

Table of Contents

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	43,752,145		$	33,473,143
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	89,896,756			43,900,774
Impairment of oil and gas properties	—			1,916,690
Deferred income taxes	27,401,606			20,556,874
Stock-based compensation	9,715,764			2,912,248
Exploration	1,688,036			7,378,612
Amortization of deferred financing costs	1,120,052			501,315
Accretion of contractual obligation for land acquisition	570,977			—
Valuation (increase) decrease in commodity derivatives	4,576,133			(2,985,356		)
Gain on sale of oil and gas properties	—			(4,279,998		)
Other	—			70,563
(Increase) decrease in operating assets:
Accounts receivable	(32,080,778		)	(18,152,964		)
Prepaid expenses and other assets	726,546			352,541
(Decrease) increase in operating liabilities:
Accounts payable and accrued liabilities	33,960,797			7,149,501
Settlement of asset retirement obligations	(73,358		)	(146,125		)
Net cash provided by operating activities	181,254,676			92,647,818
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of oil and gas properties	—			5,212,000
Acquisition of oil and gas properties	(10,968,636		)	(12,809,268		)
Payments of contractual obligations	(11,999,877		)	—
Exploration and development of oil and gas properties	(306,685,389		)	(183,357,438		)
Natural gas plant capital expenditures	(4,458,881		)	(12,009,040		)
Decrease in restricted cash	79,478			252,580
Additions to property and equipment—non oil and gas	(3,695,201		)	(2,203,315		)
Net cash (used) in investing activities	(337,728,506		)	(204,914,481		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in bank revolving credit	72,000,000			115,700,000
Payment on bank revolving credit	(191,500,000		)	—
Proceeds from sale of senior notes	300,000,000			—
Offering costs related to sale of senior notes	(7,342,526		)	—
Payment of employee tax withholdings in exchange for the return of common stock	(3,503,397		)	—
Deferred financing costs	(79,018		)	(677,428		)
Net cash provided by financing activities	169,575,059			115,022,572
NET INCREASE IN CASH AND CASH EQUIVALENTS	13,101,229			2,755,909
CASH AND CASH EQUIVALENTS:
Beginning of period	4,267,667			2,089,674
End of period	$	17,368,896		$	4,845,583
SUPPLEMENTAL CASH FLOW DISCLOSURE:
Cash paid for interest	$	2,854,886		$	1,224,331
Cash paid for income taxes	$	100,000		$	185,765
Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition	$	12,065,599		$	36,857,282
Contractual obligation for land acquisition	$	33,842,608		$	45,081,183

See accompanying notes to these consolidated financial statements.

Table of Contents

Bonanza Creek Energy, Inc.

Notes to the Consolidated Financial Statements as of September 30, 2013 (unaudited)

1. ORGANIZATION AND BUSINESS:

Bonanza Creek Energy, Inc. (the “Company” or “BCEI”) is engaged primarily in acquiring, developing, exploiting and producing oil and gas properties. As of September 30, 2013, the Company’s assets and operations are concentrated primarily in the Wattenberg Field in the Rocky Mountains and in Southern Arkansas.

2. BASIS OF PRESENTATION:

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The quarterly financial statements included herein do not necessarily include all of the disclosures as may be required under generally accepted accounting principles. The readers of these quarterly financial statements should also read the audited consolidated financial statements and related notes of BCEI that were included in BCEI’s Annual Report on Form 10-K filed with the SEC on March 15, 2013. 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 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.

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. DISCONTINUED OPERATIONS:

During June of 2012, the Company began marketing, with an intent to sell, all of its oil and gas properties in California. Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. The Company determined that its intent to sell these properties qualifies for discontinued operations. The majority of these assets were sold in 2012, while the carrying amounts of the major classes of assets and liabilities related to the operation of the remaining property that is held for sale as of September 30, 2013 and December 31, 2012 are presented below:

	As of September 30, 2013			As of December 31, 2012
PROPERTY AND EQUIPMENT:
Oil and gas properties, successful efforts method:
Proved properties	$	1,721,265		$	1,721,265
Unproved properties	629			629
Wells in progress	100,936			39,245
Total property and equipment	1,822,830			1,761,139
Less accumulated depletion and depreciation	(1,381,235		)	(1,178,751		)
Net property and equipment	$	441,595		$	582,388

Table of Contents

The current assets and liabilities related to the properties are immaterial. Total revenues and costs and expenses, and the income (loss) associated with the operation of the oil and gas properties held for sale are presented below.

	Three Months Ended September 30			Three Months Ended September 30			Nine Months Ended September 30			Nine Months Ended September 30
	2013			2012			2013			2012
NET REVENUES:
Oil and gas sales	$	403,184		$	1,274,906		$	1,277,968		$	5,000,665

OPERATING EXPENSES:
Lease operating	573,668			451,795			1,478,992			1,853,085
Severance and ad valorem taxes	382			8,809			1,058			124,298
Exploration	400			6,219			65,537			17,008
Depreciation, depletion and amortization	62,318			570,488			266,962			2,149,478
Impairment of proved properties	—			1,648,190			—			1,648,190
TOTAL COSTS AND EXPENSES	636,768			2,685,501			1,812,549			5,792,059

(LOSS) FROM OPERATIONS ASSOCIATED WITH OIL AND GAS PROPERTIES HELD FOR SALE
	$	(233,584	)	$	(1,410,595	)	$	(534,581	)	$	(791,394	)

4. RECENT ACCOUNTING PRONOUNCEMENTS

In July 2013, the FASB issued Update No. 2013-11—Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (a consensus of the FASB Emerging Issues Task Force). The update provides clarification on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. The update is effective for public entities for fiscal years, and interim periods within those years, beginning after December 15, 2013. Early adoption is permitted. The Company has not yet evaluated the impact of the update on its financial statements.

5. ACCOUNTS PAYABLE AND ACCRUED EXPENSES:

Accounts payable and accrued expenses contain the following:

	As of September 30, 2013		As of December 31, 2012
Drilling and completion costs	$	63,764,281	$	51,698,682
Accounts payable	3,829,146		10,049,131
Accrued general and administrative cost	8,134,689		5,079,462
Lease operating expense	4,947,900		2,824,300
Accrued reclamation cost	186,587		400,000
Accrued interest	9,686,569		219,494
Accrued oil and gas hedging	2,434,858		238,365
Production taxes and other	3,933,371		2,340,838

	$	96,917,401	$	72,850,272

6. LONG-TERM DEBT:

Long-term debt consisted of the following at September 30, 2013 and December 31, 2012:

	As of September 30, 2013		As of December 31, 2012
Revolving credit facility	$	38,500,000	$	158,000,000
6.75% Senior Notes	300,000,000		—
	$	338,500,000	$	158,000,000

Revolving Credit Facility—The Company’s senior secured revolving Credit Agreement (the “Revolver”), dated March 29, 2011, as amended, with a syndication of banks, including KeyBank National Association as the administrative agent and issuing lender, 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%.

Table of Contents

The borrowing base under the Revolver was $330.0 million as of September 30, 2013. The borrowing base is redetermined semiannually by May 15 and November 15 and may be re-determined up to one additional time between such scheduled determinations upon request by the Company or lenders holding 66 and 2/3% of the aggregate commitments. A letter of credit that was issued to the Colorado State Board of Land Commissioners in connection with the Company’s lease of acreage in the Wattenberg Field (Wattenberg Field Lease Acquisition) reduces the borrowing base under the Revolver by approximately $36 million as of September 30, 2013 and will be paid in equal $12 million increments over the next three years. The Revolver provides for commitment fees ranging from 0.375% to 0.50%, depending on utilization, and restricts, among other items, the payment of dividends, certain additional indebtedness, sale of assets, loans and certain investments and mergers. The Revolver also contains certain financial covenants, which require the maintenance of a minimum current ratio and a minimum debt coverage ratio, as defined. The Company was in compliance with these covenants as of September 30, 2013. The Revolver is collateralized by substantially all the Company’s assets and matures on September 15, 2016. As of September 30, 2013, there was $38.5 million outstanding and the $36.0 million letter of credit issued under the Revolver, and the Company had $255.5 million available for future borrowings under the Revolver.

Senior Notes—On April 9, 2013, the Company issued $300,000,000 of 6.75% Senior Notes (the “Senior Notes”). Interest on the Senior Notes began accruing on April 9, 2013, and the Company will pay interest on April 15 and October 15 of each year, which began on October 15, 2013. The Senior Notes mature on April 15, 2021. The Senior Notes are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Company’s revolving credit facility. The Company may redeem the Senior Notes (i) at any time on or after April 15, 2017 at the redemption price equal to 100% together with accrued and unpaid interest, and (ii) prior to April 15, 2017 at the “make-whole” redemption prices described in the indenture together with accrued and unpaid interest. The net proceeds from the sale of the Senior Notes were approximately $292.7 million after deducting $7.3 million of expenses and underwriting discounts and commissions, and a portion of the proceeds were used to repay all of the then outstanding balance of $191,500,000 under our revolving credit facility.

The Company filed a Registration Statement on Form S-4 with the SEC, which became effective June 3, 2013 and registered the offering to exchange unregistered Senior Notes for registered Senior Notes, as well as the guarantees of the Senior Notes by the Company’s subsidiaries. As of September 30, 2013, all of the existing subsidiaries of the Company are guarantors of the Senior Notes, and all such subsidiaries are 100 percent owned by the Company. The guarantees by the subsidiaries are full and unconditional (except for customary release provisions) and constitute joint and several obligations of the subsidiaries. The Company has no independent assets or operations unrelated to its investments in its consolidated subsidiaries. There are no significant restrictions on the Company’s ability or the ability of any subsidiary guarantor to obtain funds from its subsidiaries by such means as a dividend or loan.

7. COMMITMENTS AND CONTINGENT LIABILITIES:

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 ASC 450, Contingencies, 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.

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 or regulation procedures as they relate to the drilling of oil and gas wells and associated 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 cleanup or restoration, the liability to cure such a violation could fall upon the Company.

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

Commitments—The Company rents office facilities under various non-cancelable operating lease agreements. The Company’s non-cancelable operating lease agreements result in total future minimum non-cancelable lease payments presented below. The Company also has principal payment requirements for its 6.75% Senior Notes and payments on a portion of the Wattenberg Field Lease Acquisition, all of which are presented below:

Table of Contents

	Office Leases		Wattenberg Field Lease Acquisition		Interest on Senior Notes		Repayment of Senior Notes		Total
2013	$	417,321	$	—	$	10,462,500	$	—	$	10,879,821
2014	2,028,651		11,999,877		20,250,000		—		34,278,528
2015	2,016,960		11,999,877		20,250,000		—		34,266,837
2016	1,742,910		11,999,877		20,250,000		—		33,992,787
2017 and thereafter	5,690,442		—		91,125,000		300,000,000		396,815,442
	$	11,896,284	$	35,999,631	$	162,337,500	$	300,000,000	$	510,233,415

8. FAIR VALUE MEASUREMENTS:

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

Level 1:		Quoted prices are available in active markets for identical assets or liabilities;
Level 2:		Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; or
Level 3:		Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

Financial assets and liabilities 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 table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3
Commodity derivative assets	$	—	$	940,214	$	161,106
Commodity derivative liabilities	$	—	$	3,879,369	$	6,028,328

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, 2012 by level within the fair value hierarchy:

	Fair Value Measurements Using
	Level 1		Level 2		Level 3
Commodity derivative assets	$	—	$	450,872	$	1,727,192
Commodity derivative liabilities	$	—	$	5,173,140	$	1,235,168

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. Presently, all of our hedging arrangements are concentrated with six counterparties, five of which are lenders under our Company’s senior secured revolving credit facility.

Table of Contents

The following table reflects the activity for the commodity derivatives measured at fair value using Level 3 inputs during the period from January 1, 2013 through September 30, 2013:

	Derivative Asset			Derivative Liability
Beginning net asset (liability) balance	$	1,727,192		$	1,235,168
Net (decrease) increase in fair value	(4,062,935		)	5,310,842
Net realized (loss) on settlement	(586,249		)	(1,559,729		)
New derivatives	3,083,098			1,042,047
Transfers in (out) of Level 3	—			—
Ending net asset (liability) balance	$	161,106		$	6,028,328

As of September 30, 2013, the Company’s derivative commodity contracts are as follows:

Settlement Period	Swap Volume	Fixed Price	Collar Volume	Average Short Floor	Average Floor	Average Ceiling
Oil	Bbl/d	$	Bbl/d	$	$	$
Q4 2013	3,939	93.81	5,022		87.99	101.46

Q1 2014	2,133	96.19	5,617		86.33	97.09
Q2 2014	2,126	96.21	4,846		86.55	96.72
Q3 2014	1,370	94.40	4,326		86.16	96.57
Q4 2014	1,370	94.40	4,326		86.16	96.57

Q1 2014			1,000	60.00	85.00	99.50
Q2 2014			1,000	60.00	85.00	99.50
Q3 2014			1,000	60.00	85.00	99.50
Q4 2014			1,000	60.00	85.00	99.50

FY 2015			1,500	60.00	80.00	98.15

Gas		MMBtu/d		$
Q4 2013		166		6.40

The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of September 30, 2013:

Derivatives	Balance Sheet Location	Fair Value
Asset
Commodity derivatives	Current derivative assets	$	620,446
Commodity derivatives	Long-term derivative assets	480,874
Liability
Commodity derivatives	Current derivative liability	(9,613,257		)
Commodity derivatives	Long-term derivative liability	(294,440		)
Total		$	(8,806,377	)

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

Table of Contents

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

Proved Oil and Gas Properties—Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs exceed the sum of the undiscounted cash flows. The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts selected by the Company’s management. The calculation of the discount rate is a significant management estimate based on the best information available and estimated to be 10 percent for the nine months ended September 30, 2013. Management believes that the discount rate is representative of current market conditions and reflects the following factors: estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on New York Mercantile Exchange (“NYMEX”) strip pricing, adjusted for basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates.

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. Ten thousand shares of Class B common stock were available under the Plan and these shares were converted into 437,787 shares of restricted common stock upon completion of our initial public offering (“IPO”). The conversion rate was determined based on a formula factoring in the rate of return to the pre-IPO 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. For the three and nine months ended September 30, 2013, stock-based compensation expense related to the MIP grant was approximately $0.8 million and $1,926,000, respectively, and, as of September 30, 2013, there was approximately $2,690,000 of unrecognized compensation costs related to the unvested restricted common stock granted under the MIP. That cost is expected to be recognized over a period of 1.25 years. The MIP has been terminated such that there will be no future grants thereunder.

BCEC Investment Trust— The BCEC Investment Trust was formed to hold shares of our common stock received by Bonanza Creek Energy Company, LLC, our predecessor, in connection with our December 23, 2010 corporate restructuring. On February 5, 2013, 13,825 previously issued shares of our common stock that were fully vested and held by the BCEC Investment Trust were distributed to former employees. While the shares had been issued in December 2010, for accounting purposes, the date of distribution to former employees was considered the grant date, and these shares were valued at the closing price of our common stock on the grant date, which was $34.18 per share. On February 11, 2013, 59,372 previously issued shares of our common stock that were fully vested and held by the BCEC Investment Trust were distributed to certain current employees. While the shares had been issued in December 2010, for accounting purposes, the date of distribution to employees was considered the grant date, and these shares were valued at the closing price of our common stock on the grant date, which was $34.89 per share. These distributions resulted in a stock-based compensation expense of $— and $2,741,000, respectively, related to the BCEC Investment Trust during the three and nine month periods ended September 30, 2013.

2011 Long Term Incentive Plan. During 2012, the Company granted 703,246 shares of restricted common stock under its 2011 Long Term Incentive Plan (the “LTIP”) to officers and certain key employees. For accounting purposes, these shares are valued at the closing price of our common stock on the grant date and compensation expense is recognized over the vesting period. These shares will vest annually in one-third increments over three years. For the three and nine months ended September 30, 2013, stock-based compensation expense related to the 2012 LTIP grants was approximately $1.0 million and $3,151,000, respectively, and, as of September 30, 2013, there remained $5,877,000 of unrecognized compensation costs related to the unvested restricted common stock granted under the LTIP. That cost is expected to be recognized over the next 2.17 years.

During 2013, the Company granted 265,066 shares of restricted common stock under the LTIP to officers and employees. For accounting purposes, these shares are valued at the closing price of our common stock on the grant date and compensation expense is recognized over the vesting period. These shares will vest annually in one-third increments over three years. For the three and nine months ended September 30, 2013, stock-based compensation expense related to the 2013 LTIP grants was approximately $0.8 million and $1,645,000, respectively, and, as of September 30, 2013, there remained $8,450,000 of unrecognized compensation costs related to the unvested restricted stock granted under the LTIP. That cost is expected to be recognized over the next 3.0 years.

During 2013, the Company granted 41,622 Performance Stock Units (“PSUs”) under the LTIP to certain officers. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges 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 performance criterion for the PSUs is based on a comparison of the Company’s Total Shareholder Return (“TSR”) for the measurement period compared with the TSRs of a group of peer companies for the measurement period. Expense associated with PSUs is recognized as general and administrative expense over the vesting period. The fair value of the PSUs was measured at the grant date with a stochastic process method using the Geometric Brownian Motion Model (“GBM Model”). For the three and nine months ended September 30, 2013, stock-based compensation expense related to the 2013 LTIP PSU grants was approximately $102,000 and $253,000, respectively, and, as of September 30, 2013, there remained $1,094,000 of unrecognized compensation

Table of Contents

cost as of September 30, 2013 related to the unvested PSUs granted under the LTIP. That cost is expected to be recognized over the next 2.25 years.

10. EARNINGS PER SHARE:

The Company computes basic net income per share using the weighted average number of shares of common stock outstanding during the period. Diluted net income per share is computed using the weighted average number of shares of common stock and, if dilutive, potential shares of common stock outstanding during the period. The potentially dilutive shares are related to the 2013 PSU grants to certain officers. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges 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 treasury stock method is used to measure the dilutive impact of potentially dilutive shares.

The following table details the potential weighted average dilutive and anti-dilutive securities for the periods presented.

	Three Months Ended September 30	Three Months Ended September 30	Nine Months Ended September 30	Nine Months Ended September 30
	2013	2012	2013	2012

Basic weighted average number of common shares outstanding	40,266,516	39,477,101	40,209,752	39,476,133
Dilution effect of stock-based compensation awards at end of period	54,572	—	56,279	—
Diluted weighted average number of common shares outstanding	40,321,088	39,477,101	40,266,031	39,476,133
Anti-dilutive stock-based compensation awards	176,436	—	157,934	—

11. SUBSEQUENT EVENTS:

On November 6, 2013, the lenders under the Company’s revolving credit facility completed their semi-annual borrowing base redetermination which resulted in an increase of the available borrowing base to $450 million. Pursuant to the corresponding amendment, the Company elected to limit bank commitments at $330 million while reserving the option to access, at the Company’s request, the full $450 million prior to the next semi-annual redetermination. The maturity date of the credit facility was also extended by one year to September 15, 2017.

Table of Contents

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, 2012 (the “2012 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 went public 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 and the Cotton Valley sands of southern Arkansas. The low risk, oily and stable production profile of our Arkansas assets provides a strong cash flow base from which to develop 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 other high return basins across the United States where we can apply our core competencies of horizontal drilling and fracture stimulation. We maintain a high working interest in our properties.

Third Quarter 2013 Financial and Operating Highlights

· We increased production by 88% to 1,624.3 MBoe in the third quarter of 2013 from 865.0 MBoe in the third quarter of 2012. Oil and NGL production represented 72% of total production, despite negative impacts on production from vertical wells in the Wattenberg Field. The negative impacts on production from these vertical wells were due to high gas gathering pipeline pressures and curtailment of production to comply with emissions standards.

· We generated net income of $17.8 million (including approximately $17.9 million from continuing operations), as compared with $3.4 million (including approximately $1.6 million from continuing operations) for the third quarter of 2012. The increase in net income (including net income from continuing operations) as compared to the third quarter of 2012 was related to an 88% increase in Boe production with a corresponding 15% increase to the average sales price per Boe.

Outlook for 2013

We continue to monitor the outlook for the global economy and numerous critical factors, including the United States federal budget deficit and long-term fiscal situation and the European debt crisis, and their potential impacts on global economic growth and commodity prices. 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 2013 to be approximately $460 to $475 million, allocated approximately 80% to the Wattenberg Field and 20% to southern Arkansas. During the nine months ended September 30, 2013, we incurred capital expenditures of $331.4 million. Actual capital expenditures are subject to a number of factors, including economic conditions and commodity prices, and the Company may reduce or augment the budget as appropriate. This capital investment is expected to produce 2013 average sales volumes of 14,500 to 16,000 Boe/d, while maintaining a strong oil and liquids profile.

Table of Contents

Results for Continuing Operations

Three Months Ended September 30, 2013 Compared To Three Months Ended September 30, 2012

Revenues

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

	Three Months Ended September 30,
	2013		2012		Change			Percent Change
	(In thousands, except per unit amounts)
Revenues:
Crude oil sales	$	108,263	$	49,755	$	58,508		118	%
Natural gas sales	12,297		4,668		7,629			163	%
Natural gas liquids sales	5,387		3,757		1,630			43	%
CO2 sales	26		148		(122		)	(82	)%
Product revenues	$	125,973	$	58,328	$	67,645		116	%

	Three Months Ended September 30,
	2013	2012	Change	Percent Change
Sales volumes:
Crude oil (MBbls)	1,078.6	567.0	511.6	90	%
Natural gas (MMcf)	2,687.7	1,388.6	1,299.1	94	%
Natural gas liquids (MBbls)	97.7	66.6	31.1	47	%
Crude oil equivalent (MBoe)(1)	1,624.3	865.0	759.3	88	%

	Three Months Ended September 30,
	2013		2012		Change			Percent Change
Average Sales Prices (before hedging)(2):
Crude oil (per Bbl)	$	100.37	$	87.75	$	12.62		14	%
Natural gas (per Mcf)	4.58		3.36		1.22			36	%
Natural gas liquids (per Bbl)	55.14		56.41		(1.27		)	(2	)%
Crude oil equivalent (per Boe)(1)	77.54		67.26		10.28			15	%

	Three Months Ended September 30,
	2013		2012		Change			Percent Change
Average Sales Prices (after hedging)(2):
Crude oil (per Bbl)	$	93.88	$	86.89	$	6.99		8	%
Natural gas (per Mcf)	4.62		3.65		0.97			27	%
Natural gas liquids (per Bbl)	55.14		56.41		(1.27		)	(2	)%
Crude oil equivalent (per Boe)(1)	73.31		67.15		6.16			9	%

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

(2) 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.

Revenues increased by 116%, to $126.0 million for the three months ended September 30, 2013 compared to $58.3 million for the three months ended September 30, 2012, due to increased production and higher crude oil and natural gas prices. Oil, natural gas, and natural gas liquids production increased 90%, 94%, and 47%, respectively, during the three months ended September 30, 2013, as compared to the three months ended September 30, 2012. During the period from September 30, 2012 through September 30, 2013, we drilled and completed 80 gross (71.8 net) wells in the Rockies and 47 gross (41.0 net) wells in southern Arkansas. The increased volumes are a direct result of the $340.8 million expended for drilling and completion during the year ended December 31, 2012, and the $331.4 million expended during the nine months ended September 30, 2013. Oil prices increased from an average per barrel rate of $87.75 in the third quarter of 2012 to a per barrel rate of $100.37 in the comparable three month period that ended September 30, 2013. Increased oil volumes of 90% accounted for $58.5 million of the total $67.6 million increase in revenues for

Table of Contents

the Company for the three month period ended September 30, 2013 compared to the same period in 2012. Increased natural gas volumes and prices of 94% and 36%, respectively, accounted for $7.6 million of the total $67.6 million increase in revenues for the Company for the three month period ended September 30, 2013. Natural gas liquids volumes increased by 47% in 2013 with prices decreasing by 2% to $55.14 from $56.41 for the three months ended September 30, 2013 compared to the three months ended September 30, 2012. Our Wattenberg Field natural gas is sold without processing into dry gas and NGLs and, therefore, sells at a premium due to its high BTU content. Our production of oil, natural gas, and natural gas liquids for the three months ended September 30, 2013 was approximately 66%, 28% and 6%, respectively.

While production volumes increased by 88% during the three months ended September 30, 2013, production volumes were adversely impacted by high gas gathering pipeline pressures, and emissions compliance. During the latter half of 2012 and throughout 2013, our Wattenberg Field production was adversely impacted by increasing line pressures on the gathering system operated by our third-party service provider. We and other operators in the field are working closely with our primary midstream provider in the Wattenberg Field who is implementing a multi-year facility expansion capable of significantly increasing long-term gathering and processing capacity. We expect increased gas processing capacity to be available to improve line pressures to some extent late in 2013. In addition, during the three months ended September 30, 2013, the Company deferred well maintenance activities to comply with emissions standards, effectively curtailing production from certain vertical wells.

Operating Expenses

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

	Three Months Ended September 30,
	2013		2012		Change			Percent Change
	(In thousands, except percentages)
Expenses:
Lease operating	$	12,958	$	8,444	$	4,514		53	%
Severance and ad valorem taxes	8,086		3,022		5,064			168	%
General and administrative	13,811		9,335		4,476			48	%
Depreciation, depletion and amortization	36,750		17,716		19,034			107	%
Impairment of oil and gas properties	—		269		(269		)	(100	)%
Exploration	2,099		6,359		(4,260		)	(67	)%
Operating expenses	$	73,704	$	45,145	$	28,559		63	%

	Three Months Ended September 30,
	2013		2012		Change			Percent Change
Selected Costs ($ per Boe):
Lease operating	$	7.98	$	9.76	$	(1.78	)	(18	)%
Severance and ad valorem taxes	4.98		3.49		1.49			43	%
General and administrative	8.50		10.79		(2.29		)	(21	)%
Depreciation, depletion and amortization	22.63		20.48		2.15			10	%
Impairment of oil and gas properties	—		0.31		(.31		)	(100	)%
Exploration	1.29		7.35		(6.06		)	(82	)%
Operating expenses	$	45.38	$	52.18	$	(6.80	)	(13	)%

Lease Operating Expense. Our lease operating expenses increased $4.6 million, or 53%, to $13.0 million for the three months ended September 30, 2013 from $8.4 million for the three months ended September 30, 2012 but decreased on an equivalent basis from $9.76 per Boe to $7.98 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 2012 but did not come on line until February of 2013. During the three months ended September 30, 2013, well servicing, pumping and compression expenses were $2.2 million, $0.8 million and $0.6 million higher, respectively, than the three months ended September 30, 2012. Gas plant operating expense, which is a component of lease operating expense, increased $0.9 million, or 37%, to $3.4 million for the three month period ended September 30, 2013 from $2.5 million for the three month period ended September 30, 2012. Our lease operating expense per Boe decreased due to higher production volumes from our lower operating cost horizontal wells in the Wattenberg Field.

Severance and ad valorem taxes. Our severance and ad valorem taxes increased $5.1 million, or 168%, to $8.1 million for the three months ended September 30, 2013 from $3.0 million for the three months ended September 30, 2012. The increase was primarily related to an 88%

Table of Contents

increase in production volumes with a corresponding 15% increase in the average sales price per Boe for the three months ended September 30, 2013 as compared to the three months ended September 30, 2012.

General and administrative. Our general and administrative expense increased $4.5 million, or 48%, to $13.8 million for the three months ended September 30, 2013 from $9.3 million for the period ended September 30, 2012 and decreased on an equivalent basis to $8.50 per Boe from $10.79 per Boe. During the three months ended September 30, 2013, wages and benefits, stock-based compensation and professional services were $3.8 million, $1.2 million and $1.1 million higher, respectively, than in the three month period ended September 30, 2012. The increase in general and administrative expense is primarily due to increased headcount and increased participation in the long term and short term incentive programs for the Company. General and Administrative expenses were offset by a reduction in legal fees of $1.6 million primarily related to the successful completion of the previously disclosed Bennett matter which resulted in a reimbursement of a portion of our incurred legal fees.

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased $19.0 million, or 107%, to $36.7 million for the three months ended September 30, 2013 from $17.7 million for the three months ended September 30, 2012. Our depreciation, depletion and amortization expense per Boe produced increased $2.15, or 10% to $22.63 for the three months ended September 30, 2013 as compared to $20.48 for the three months ended September 30, 2012. The increase per Boe is related to an 88% increase in production with a corresponding increase in proved developed reserves of 54%.

Exploration costs. Our exploration expense decreased $4.3 million to $2.1 million in the three months ended September 30, 2013 from $6.4 million in the three months ended September 30, 2012. During the three months ended September 30, 2013 a non-core lease in the North Park basin expired which resulted in a $1.7 million non-cash exploration charge to our statement of operations. During the three months ended September 30, 2012, a seismic acquisition project in the North Park Basin of Colorado was completed which resulted in charges of approximately $0.3 million, delay rentals were $0.2 million, and two exploratory locations in the North Park basin were charged to exploration expense which resulted in a $5.8 million charge to our statement of operations.

Interest expense. Our interest expense for the three months ended September 30, 2013 increased $5.1 million, or 449%, to $6.2 million compared to $1.1 million for the three months ended September 30, 2012. The increase for the three months ended September 30, 2013 compared to the three months ended September 30, 2012 is primarily related to the issuance of $300 million in 6.75% Senior Notes on April 9, 2013 which accounted for $5.2 million of the $6.2 million of interest expense during the three months ended September 30, 2013.

Realized loss on settled commodity derivatives. Realized losses on oil and gas hedging activities increased by $6.8 million for the three months ended September 30, 2013. The realized losses were $6.9 million and $0.1 million for the three months ended September 30, 2013 and 2012, respectively. Realized losses on oil and gas hedging activities during the three months ended September 30, 2013 were $6.9 million of which $2.2 million was related to collars covering 372,000 Boe and swaps of $4.7 million covering 300,547 Boe. During this time frame the average NYMEX price was $105.82 and our average settled collar and swap prices were $98.73 and $88.03, respectively. Total hedged volume for the three months ended September 30, 2013 was 762,547 Boe, of which oil collars covering 90,000 Bbls did not trigger any cash settlements and resulted in no gain or loss for the period.

Table of Contents

Income tax expense. Our estimate for federal and state income taxes for the three months ended September 30, 2013 was $11.2 million from continuing operations as compared to $1.2 million for the three months ended September 30, 2012. 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 period ended September 30, 2013 was 38.5% which differs from the U.S. statutory income rate primarily due to the effects of state income taxes. Our effective tax rate for the three month period ended September 30, 2012 was revised to reflect a 35% rate for federal income taxes. This revision, when aggregated with the effects of state income taxes, resulted in an effective tax rate of 42.6% for the three month period ended September 30, 2012.

Nine Months Ended September 30, 2013 Compared To Nine Months Ended September 30, 2012

Revenues

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

	Nine Months Ended September 30,
	2013		2012		Change			Percent Change
	(In thousands, except per unit amounts)
Revenues:
Crude oil sales	$	245,112	$	133,880	$	111,232		83	%
Natural gas sales	30,325		12,238		18,087			148	%
Natural gas liquids sales	13,269		11,315		1,954			17	%
CO2 sales	92		180		(88		)	(49	)%
Product revenues	$	288,798	$	157,613	$	131,185		83	%

	Nine Months Ended September 30,
	2013	2012	Change	Percent Change
Sales volumes:
Crude oil (MBbls)	2,599.9	1,462.6	1137.3	78	%
Natural gas (MMcf)	6,648.2	3,740.7	2,907.5	78	%
Natural gas liquids (MBbls)	251.8	202.4	49.4	24	%
Crude oil equivalent (MBoe)(1)	3,959.7	2,288.5	1,671.2	73	%

	Nine Months Ended September 30,
	2013		2012		Change			Percent Change
Average Sales Prices (before hedging)(2):
Crude oil (per Bbl)	$	94.28	$	91.53	$	2.75		3	%
Natural gas (per Mcf)	4.56		3.27		1.29			39	%
Natural gas liquids (per Bbl)	52.70		55.90		(3.20		)	(6	)%
Crude oil equivalent (per Boe)(1)	72.91		68.75		4.16			6	%

	Nine Months Ended September 30,
	2013		2012		Change			Percent Change
Average Sales Prices (after hedging)(2):
Crude oil (per Bbl)	$	90.34	$	90.16	$	0.18		0.2	%
Natural gas (per Mcf)	4.62		3.49		1.13			32	%
Natural gas liquids (per Bbl)	52.70		55.90		(3.20		)	(6	)%
Crude oil equivalent (per Boe)(1)	70.42		68.28		2.14			3	%

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

(2) 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.

Revenues increased by 83%, to $288.8 million for the nine months ended September 30, 2013 compared to $157.6 million for the nine months ended September 30, 2012, due to increased production and higher crude oil and natural gas prices. Oil, natural gas, and natural gas liquids production increased 78%, 78%, and 24%, respectively, during the nine months ended September 30, 2013, as compared to the nine months ended September 30, 2012. During the period from September 30, 2012

Table of Contents

through September 30, 2013, we drilled and completed 80 gross (71.8 net) wells in the Rockies and 47 gross (41.0 net) wells in southern Arkansas. The increased volumes are a direct result of the $340.8 million expended for drilling and completion during the year ended December 31, 2012, and the $331.4 million expended during the nine months ended September 30, 2013. Oil volumes increased by 78% in 2013, and the sales price increased 3% from $91.53 per barrel during the nine months ended September 30, 2012 to $94.28 per barrel during the nine month period ended September 30, 2013, which accounted for a $111.2 million increase in revenues. Natural gas volumes increased by 78% in 2013, and were aided by an increase in sales price of 39% from $3.27 per Mcf to $4.56 per Mcf for these nine month periods, which accounted for $18.1 million of the increase in revenues. Natural gas liquid volumes increased by 24% in 2013, but were offset by a sales prices decline of 6% from $55.90 per Bbl to $52.70 per Bbl for these nine month periods. Our Wattenberg Field natural gas is sold without processing into dry gas and NGLs and, therefore, and sells at a premium due to its high BTU content.

Operating Expenses

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

	Nine Months Ended September 30,
	2013		2012		Change			Percent Change
	(In thousands, except percentages)
Expenses:
Lease operating	$	36,986	$	22,506	$	14,480		64	%
Severance and ad valorem taxes	18,251		9,387		8,864			94	%
General and administrative	40,260		22,410		17,850			80	%
Depreciation, depletion and amortization	89,630		41,751		47,879			115	%
Impairment of oil and gas properties	—		269		(269		)	(100	)%
Exploration	3,524		9,564		(6,040		)	(63	)%
Operating expenses	$	188,651	$	105,887	$	82,764		78	%

	Nine Months Ended September 30,
	2013		2012		Change			Percent Change
Selected Costs ($ per Boe):
Lease operating	$	9.34	$	9.83	$	(0.49	)	(5	)%
Severance and ad valorem taxes	4.61		4.10		0.51			12	%
General and administrative	10.17		9.79		0.38			4	%
Depreciation, depletion and amortization	22.64		18.24		4.40			24	%
Impairment of oil and gas properties	—		0.12		(0.12		)	(100	)%
Exploration	0.89		4.18		(3.29		)	(79	)%
Operating expenses	$	47.65	$	46.26	$	1.39		3	%

Lease Operating Expense. Our lease operating expenses increased $14.5 million, or 64%, to $37 million for the nine months ended September 30, 2013 from $22.5 million for the nine months ended September 30, 2012 and decreased on an equivalent basis from $9.83 per Boe to $9.34 per Boe. The increase in lease operating expense was related to the increased production volumes attributable to our drilling program and the operation of an additional gas plant that was constructed during 2012 but did not come on line until February of 2013. During the nine months ended September 30, 2013, well servicing, compression, and pumping were also $6.4 million, $1.8 million, $1.7 million higher, respectively, than the nine months ended September 30, 2012. Gas plant operating expense, which is a component of lease operating expense, increased $3.5 million, or 54%, to $10 million for the nine month period ended September 30, 2013 from $6.5 million for the nine month period ended September 30, 2012. While our lease operating expense per Boe decreased due to higher production from our lower cost horizontal wells in the Wattenberg Field we were still impacted by high gas gathering pipeline pressures and emission compliance standards which resulted in production that was less than anticipated, as previously discussed in the three months ended September 30, 2013 results. In Southern Arkansas the replacement of essential gas plant processing equipment cost approximately $0.4 million to install and our newly constructed gas plant is not yet operating at full capacity which also increased our lease operating expense rate per Boe.

Severance and ad valorem taxes. Our severance and ad valorem taxes increased $8.9 million, or 94%, to $18.3 million for the nine months ended September 30, 2013 from $9.4 million for the nine months ended September 30, 2012. The increase was primarily related to a 73% increase in production volumes with a corresponding 6% increase in the average sales price per Boe for the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012.

General and administrative. Our general and administrative expense increased $17.9 million, or 80%, to $40.3 million for the nine months ended September 30, 2013 from $22.4 million for the nine months ended September 30, 2012 and increased on an equivalent basis from $9.79 per Boe to $10.17 per Boe. During the nine months ended September 30, 2013, wages and benefits, stock-based compensation, professional services and public company expenses were $8.8 million, $6.8 million, $2.5 million and $0.6 million higher than the nine month period ended September 30, 2012.

Table of Contents

The increase in general and administrative expense is primarily due to increased headcount and increased participation in the long term and short term incentive programs for the Company. General and Administrative expenses were offset by a reduction in legal fees of $1.0 million primarily related to the successful completion of the previously disclosed Bennett matter which resulted in a reimbursement of a portion of our incurred legal fees.

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense increased $47.9 million, or 115%, to $89.6 million for the nine months ended September 30, 2013 from $41.7 million for the nine months ended September 30, 2012. Our depreciation, depletion and amortization expense per Boe produced increased $4.40, to $22.64 for the nine months ended September 30, 2013 as compared to $18.24 for the nine months ended September 30, 2012. The increase per Boe is related to a 73% increase in production with a corresponding increase in proved developed reserves of 54%.

Exploration costs. Our exploration expense decreased $6.0 million, or 63%, to $3.5 million in the nine months ended September 30, 2013 from $9.5 million in the nine months ended September 30, 2012. Seismic and 3D data acquisitions for the Wattenberg Field made up $1.4 million of the $3.5 million for the nine months ended September 30, 2013 with an additional $1.7 million related to the expiration of a non-core lease in the North Park basin which resulted in a non-cash exploration charge to our statement of operations. During the nine months ended September 30, 2012, the following items in the North Park basin were charged to exploration expense: a seismic acquisition project in the amount of $1.9 million and three exploratory locations totaling $7.4 million were written off to exploration expense.

Interest expense. Our interest expense increased $11.7 million, or 498%, to $14.0 million for the nine months ended September 30, 2013 from $2.3 million for the nine months ended September 30, 2012. The increase for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 is primarily related to the issuance of $300 million in 6.75% Senior Notes on April 9, 2013. Interest expense for the Senior Notes was $10.1 million, of which $0.5 million was related to the amortization of debt issuance costs related to the Senior Notes offering, for the nine months ended September 30, 2013. Interest expense on our revolving credit facility was $2.7 million for the nine month period ended September 30, 2013. Approximately $0.7 million of our interest expense was related to non-cash charges for the amortization of debt issuance costs associated with our revolving credit facility and approximately $0.6 million was related to the accretion of our contractual obligation for land acquisition, as compared to total interest expense of $2.3 million for the nine month period ended September 30, 2012. The average outstanding long-term debt balance during the nine months ended September 30, 2013 was $262.1 million as compared to $60.5 million for the nine months ended September 30, 2012.

Realized loss on settled commodity derivatives. Realized losses on oil and gas hedging activities increased by $8.7 million for the nine months ended September 30, 2013. The realized losses were $9.9 million and $1.2 million for the nine months ended September 30, 2013 and 2012, respectively. Realized losses on oil and gas hedging activities during the nine months ended September 30, 2013 were $9.9 million of which $2.2 million was related to collars covering 392,000 Boe and $7.7 million related to swaps covering 841,763 Boe. During this time frame the average NYMEX price was $98.14 and our average settled collar and swap prices were $99.23 and $87.16, respectively. Total hedged volume for the nine months ended September 30, 2013 was 1,894,879 Boe, of which oil collars covering 661,116 Bbls did not trigger any cash settlements and resulted no gain or loss for the period.

Table of Contents

Income tax expense. Our estimate for federal and state income taxes for the nine months ended September 30, 2013 was $27.6 million from continuing operations as compared to $19.8 million for the nine months ended September 30, 2012. 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 period ended September 30, 2013 was 38.5% as compared to 38.7% for the period ended September 30, 2012, which differs from the U.S. statutory income 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 majority of these properties were sold in 2012, and the operating results before income taxes for our remaining California properties for the three month period ended September 30, 2013 were net revenues of $0.4 million, and operating expenses of $0.6 million, as compared to net revenues of $1.3 million, and operating expenses of $2.7 million for the three month period ended September 30, 2012. Sales volumes for the three month periods ended September 30, 2013 and 2012 were 41 Boe/d and 143 Boe/d, respectively.

The operating results before income taxes for our California properties for the nine month period ended September 30, 2013 were net revenues of $1.3 million, and operating expenses of $1.8 million, as compared to net revenues of $5.0 million, and operating expenses of $5.8 million for the nine month period ended September 30, 2012. Sales volumes for the nine month periods ended September 30, 2013 and 2012 were 47 Boe/d and 182 Boe/d, respectively.

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.

On April 9, 2013, we sold $300,000,000 of 6.75% Senior Notes (the “Senior Notes”). Interest on the Senior Notes began accruing on April 9, 2013, and we will pay interest on April 15 and October 15 of each year, which began on October 15, 2013. The Senior Notes mature on April 15, 2021. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by our existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under our revolving credit facility. We may redeem the Senior Notes (i) at any time on or after April 15, 2017 at the redemption price equal to 100% together with accrued and unpaid interest, and (ii) prior to April 15, 2017 at the “make-whole” redemption prices described in the indenture together with accrued and unpaid interest. The net proceeds from the sale of the Senior Notes were approximately $292.7 million after deducting $7.3 million of expenses and underwriting discounts and commissions. A portion of the proceeds were used to repay all of the then outstanding balance of $191,500,000 under our revolving credit facility.

In the second quarter 2012, we began the divestiture process of our non-core properties in California. The California properties were treated as assets held for sale, and production, revenue and expenses associated with these properties were removed from continuing operations and reported as discontinued operations. During 2012, we sold a majority of our properties in California, for approximately $9.3 million in aggregate.

On July 31, 2012, we acquired leases in the Wattenberg Field from the State of Colorado, State Board of Land Commissioners. We paid approximately $12 million at closing, another $12 million on July 31st of 2013, and will pay approximately $12 million on July 31st of each of the next three years. These future payments are secured by a letter of credit which reduced the borrowing base under our credit facility by $36 million as of September 30, 2013.

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 (ii) make changes in the covenant applicable to hedging to allow greater flexibility for management to implement comprehensive hedging plans to adequately protect our operations and capital budgets. On May 15, 2013, our borrowing base was increased to $330 million, and as of September 30, 2013, we had $38.5 million outstanding, $36.0 million of letters of credit issued, and $255.5 million of borrowing capacity available under our credit facility. Our weighted-average interest rate on borrowings from our credit facility was 1.94% (excluding amortization of deferred financing costs and the accretion of our contractual obligation for land acquisition) during the nine months ended September 30, 2013. On November 6, 2013, the lenders completed their semi-annual borrowing base redetermination which resulted in an increase of the available borrowing base to $450 million. Pursuant to the corresponding amendment, the company elected to limit bank commitments at $330 million while reserving the option to access, at the Company’s request the full $450 million prior to the next semi-annual redetermination. The maturity date of the credit facility was also extended by one year to September 15, 2017.

Table of Contents

We expect that 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 about Market Risks” of this Quarterly Report on Form 10-Q.

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.

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

	Nine Months Ended September 30,
	2013			2012
	(In thousands)
Net cash provided by operating activities	$	181,255		$	92,648
Net cash used in investing activities	(337,729		)	(204,914		)
Net cash provided by financing activities	169,575			115,023
Cash and cash equivalents	17,369			4,846
Acquisitions of oil and gas properties	10,969			12,809
Exploration and development of oil and gas properties and investment in gas processing facility	311,144			195,366

Cash flows provided by operating activities

Net cash provided by operating activities was $181.3 million for the nine months ended September 30, 2013, compared to $92.6 million provided by operating activities for the nine months ended September 30, 2012. The increase in cash from operating activities resulted primarily from an increase in revenues from increased production adjusted by cash utilized in connection with changes in operating assets and liabilities when comparing periods. Cash provided by changes in operating assets and liabilities for the nine months ended September 30, 2013 was $2.6 million compared to $10.7 million that was utilized by changes in operating assets and liabilities for the comparable period during 2012. The increase in operating assets and liabilities of $2.6 million for the nine months ended September 30, 2013 is comprised of increases in accounts receivable of $32.1 million, a decrease in prepaid expenses of $0.7 million and an increase in accounts payable and accrued liabilities (exclusive of capital accruals) of $34.0 million. The decrease in operating assets and liabilities of $10.7 million for the nine month period ended September 30, 2012 is comprised of increases in accounts receivable of $18.2 million and a decrease in prepaid expenses of $0.4 million offset by an increase in accounts payable and accrued liabilities (exclusive of capital accruals) of $7.1 million.

Cash flows used in investing activities

Expenditures for development of oil and natural gas properties and natural gas plants are the primary use of our capital resources. Net cash used in investing activities for the nine months ended September 30, 2013 was $337.7 million, compared to $204.9 million used in investing activities for the nine months ended September 30, 2012. For the nine months ended September 30, 2013, cash used for the acquisition of oil and gas properties was $11.0 million, cash used for payments of contractual obligations was $12.0 million and cash used for the development of oil and natural gas properties (including cash used for natural gas plant capital expenditures) was $311.1 million. For the nine months ended September 30, 2012, cash used for the acquisition of oil and gas properties was $12.8 million, and cash used for the development of oil and natural gas properties (including cash used for natural gas plant capital expenditures) was $195.4 million.

Cash provided by financing activities

Net cash provided by financing activities for the nine months ended September 30, 2013 was $169.6 million related to borrowings on our line of credit in the amount of $72.0 million and our Senior Notes in the amount of $300 million which were offset by payments on our line of credit in the amount of $191.5 million. The offering costs for the Senior Notes were approximately $7.3 million and cash used to satisfy employee tax withholdings for restricted stock that vested during the period was $3.5 million. Net cash provided by financing activities for the nine months ended September 30, 2012 was $115.0 million related to borrowings on our line of credit.

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 Note 4 Recent Accounting Pronouncements in the Notes to the Financial Statements.

Table of Contents

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, 2012.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the nine month periods ended September 30, 2013 and 2012. 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.

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. 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. Forward-looking statements may include statements about:

· our financial position;

· estimates of loss contingencies;

· impact of changes in oil and gas prices;

· liability for environmental and restoration obligations;

· our cash flow and liquidity;

· anticipated amount and allocation of capital expenditures;

· impact of high gas gathering pipeline pressures and emission compliance on production and results of operations;

· sufficiency of our cash on hand, cash flow from operating activities and availability under our revolving credit facility to fund our planned capital expenditures and operating expenses and comply with our debt covenants;

· anticipated amount of production and percentage of liquids production;

· anticipated depreciation, depletion and amortization in southern Arkansas;

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

· compliance with local, state and federal regulation;

· fair value measurements;

· estimated discount rate;

· impact of derivative positions on our cash flows;

· inflationary pressures;

Table of Contents

· creditworthiness of counterparties and the impact of a counterparty’s failure to perform;

· change in internal controls and risk factors; and

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

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 may differ materially from the results anticipated by these forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to, the following:

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

· ability to maintain effective internal controls;

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

Table of Contents

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. Utilizing the actual derivative contractual volumes at September 30, 2013, a 10% increase in underlying commodity prices would reduce the fair value of our derivative instruments by $33.5 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $27.2 million as of September 30, 2013. A gain or loss, however, eventually would be offset substantially by the actual sales value of the physical production covered by the derivative instruments. For additional information regarding the Company’s commodity derivative transactions, see Note 8—Fair Value Measurements and Asset Retirement Obligations in the Notes to the financial statements included in this Quarterly Report on Form 10-Q.

Our primary commodity risk management objective is to reduce volatility in our cash flows. 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. 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 hedging arrangements are concentrated with six counterparties, five 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 three business days before we receive market price cash payments from our customers. This could have a material adverse effect on our cash flows for the period between hedge settlement and payment for revenues earned.

The following table provides a summary of derivative contracts as of September 30, 2013.

Settlement Period	Swap Volume	Fixed Price	Collar Volume	Average Short Floor	Average Floor	Average Ceiling	Fair Market Value of Asset (Liability) as of September 30, 2013
Oil	Bbl/d	$	Bbl/d	$	$	$	$
Q4 2013	3,939	93.81	5,022		87.99	101.46	(4,076,085	)
Q1 2014	2,133	96.19	5,617		86.33	97.09	(2,400,084	)
Q2 2014	2,126	96.21	4,846		86.55	96.72	(1,099,043	)
Q3 2014	1,370	94.40	4,326		86.16	96.57	(545,868	)
Q4 2014	1,370	94.40	4,326		86.16	96.57	26,496

Q1 2014			1,000	60.00	85.00	99.50	(576,084	)
Q2 2014			1,000	60.00	85.00	99.50	(292,206	)
Q3 2014			1,000	60.00	85.00	99.50	(47,682	)
Q4 2014			1,000	60.00	85.00	99.50	157,337

FY 2015			1,500	60.00	80.00	98.15	2,601

Gas	MMBtu/d	$
Q4 2013	166	6.40	44,241
			$	(8,806,377	)

Table of Contents

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our management, including our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2013. 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 September 30, 2013, 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(e) of the Exchange Act during the quarter ended September 30, 2013 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 oil and gas 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, we are aware of no material pending or overtly threatened legal actions against us.

Item 1A. Risk Factors.

Our business faces many risks. Any of the risk factors discussed in this Report, Item 1A of our 2012 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 and nine month periods ended September 30, 2013, 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.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.

PART I — FINANCIAL INFORMATION	2
Item 1. — Financial Statements (Unaudited)	2
Consolidated Balance Sheets at September 30, 2013 and December 31, 2012	2
Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2013 and 2012	3

Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012	4
Notes to the Condensed Consolidated Financial Statements	5
Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations	12
Item 3. — Quantitative and Qualitative Disclosures About Market Risk	24
Item 4. — Controls and Procedures	25
PART II — OTHER INFORMATION	25
Item 1. — Legal Proceedings	25
Item 1A. — Risk Factors	25
Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds	25
Item 3. — Defaults Upon Senior Securities	25
Item 4. — Mine Safety Disclosures	25
Item 5. — Other Information	25
Item 6. — Exhibits	26
SIGNATURES	27
EXHIBIT INDEX

Exhibit No.		Description of Exhibit

10.1		Employment Letter Agreement, dated August 6, 2013, between Bonanza Creek Energy, Inc. and William J. Cassidy (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 13, 2013)

10.2		Employment Letter Agreement, dated August 7, 2013, between Bonanza Creek Energy, Inc. and Anthony G. Buchanon (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on August 13, 2013)

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

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

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

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

101		The following materials from the Bonanza Creek Energy, Inc. Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, formatted in XBRL (Extensible Business Reporting Language) include (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Cash Flows and (iv) Notes to the 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.

		BONANZA CREEK ENERGY, INC.

Date:	November 7, 2013	By:	/s/ Michael R. Starzer
		Michael R. Starzer
		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, Controller and Treasurer
		(principal accounting officer)