10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2014

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. ☒  Yes ☐  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).☒Yes ☐  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☒	Accelerated filer☐
Non-accelerated filer☐	Smaller reporting company☐
(Do not check if a smaller reporting company)

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. As of November3, 2014, the registrant had 41,237,932 shares of common stock outstanding.

BONANZA CREEK ENERGY, INC.

INDEX

			PAGE
Part I.	FINANCIAL INFORMATION
	Item 1.	Financial Statements (Unaudited)
		Condensed Consolidated Balance Sheets September 30, 2014, and December 31, 2013	3
		Condensed Consolidated Statements of Operations and Comprehensive IncomeThree and Nine Months Ended September 30, 2014, and 2013	4
		Condensed Consolidated Statements of Cash Flows Nine Months Ended September 30, 2014, and 2013	5
		Notes to Condensed Consolidated Financial Statements	6
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	26
	Item 4.	Controls and Procedures	27
Part II.	OTHER INFORMATION
	Item 1.	Legal Proceedings	27
	Item 1A.	Risk Factors	27
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	28
	Item 3.	Defaults Upon Senior Securities	28
	Item 4.	Mine Safety Disclosures	28
	Item 5.	Other Information	28
	Item 6.	Exhibits	28

2

PART I - FINANCIAL INFORMATION

Item 1.        Financial Statements.

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	September 30, 2014		December 31, 2013
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	92,618	$	180,582
Accounts receivable:
Oil and gas sales		72,292		57,485
Joint interest and other		21,945		12,915
Prepaid expenses and other		3,924		1,638
Inventory of oilfield equipment		9,996		10,696
Derivative asset		13,300		858
Total current assets		214,075		264,174
Property and equipment  (successful efforts method), at cost:
Proved properties		1,753,604		1,257,288
Less: accumulated depreciation, depletion and amortization		(377,733)		(224,848)
Total proved properties, net		1,375,871		1,032,440
Unproved properties		213,251		45,081
Wells in progress		155,096		110,848
Natural gas plant, net of accumulated depreciation of $7,819 in 2014 and $5,903 in 2013		68,479		71,474
Other property and equipment, net of accumulated depreciation of $5,168 in 2014 and $2,822 in 2013		10,511		7,406
Oil and gas properties held for sale, net of accumulated depreciation, depletion, and amortization of $ - in 2014 and $1,463 in 2013 (Note 4)		—		360
Total property and equipment, net		1,823,208		1,267,609
Long-term derivative asset		5,224		293
Other noncurrent assets		23,724		13,859
Total assets	$	2,066,231	$	1,545,935
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses (Note 5)	$	172,568	$	121,665
Oil and gas revenue distribution payable		45,951		36,241
Contractual obligation for land acquisition		12,000		12,000
Derivative liability		—		5,320
Total current liabilities		230,519		175,226
Long-term liabilities:
Revolving credit facility (Note 6)		—		—
6.75% Senior Notes due 2021, net of unamortized premium of $7,926 in 2014 and $8,847 in 2013		507,926		508,847
5.75% Senior Notes due 2023		300,000		—
Contractual obligation for land acquisition		10,604		22,033
Ad valorem taxes		29,208		18,867
Derivative liability		—		1,203
Deferred income taxes, net		192,050		152,681
Asset retirement obligations		15,382		11,050
Total liabilities		1,285,689		889,907
Commitments and contingencies (Note 7)
Stockholders’ equity:
Preferred stock, $.001 par value, 25,000,000 shares authorized, none outstanding		—		—
Common stock, $.001 par value, 225,000,000 shares authorized, 41,242,936 and 40,285,919issued and outstanding in 2014 and 2013, respectively		41		40
Additional paid-in capital		588,794		527,752
Retained earnings		191,707		128,236
Total stockholders’ equity		780,542		656,028
Total liabilities and stockholders’ equity	$	2,066,231	$	1,545,935

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

3

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS  AND COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands, except per share amounts)
Operating net revenues:
Oil and gas sales	$	156,371	$	125,973	$	435,448	$	288,798
Operating expenses:
Lease operating		18,217		12,958		53,316		36,986
Severance and ad valorem taxes		15,334		8,086		42,347		18,251
Exploration		3,291		2,099		4,470		3,524
Depreciation, depletion and amortization		63,241		36,750		158,489		89,630
General and administrative (including $3,162,  $2,652,  $17,312, and $9,716, respectively, of stock-based compensation)		14,814		13,811		63,075		40,260
Total operating expenses		114,897		73,704		321,697		188,651
Income from operations		41,474		52,269		113,751		100,147
Other income (expense):
Derivative gain (loss)		50,846		(16,890)		14,761		(14,443)
Interest expense		(13,228)		(6,180)		(31,997)		(14,013)
Other income (loss)		181		(53)		397		(3)
Total other income (expense)		37,799		(23,123)		(16,839)		(28,459)
Income from continuing operations before taxes		79,273		29,146		96,912		71,688
Income tax expense		(30,419)		(11,221)		(37,216)		(27,607)
Income from continuing operations	$	48,854	$	17,925	$	59,696	$	44,081
Discontinued operations (Note 4):
Loss from operations associated with oil and gas properties held for sale		—		(234)		(85)		(535)
Gain (loss) on sale of oil and gas properties		(117)		—		6,213		—
Income tax (expense) benefit		45		90		(2,353)		206
Gain (loss) from discontinued operations		(72)		(144)		3,775		(329)
Net income	$	48,782	$	17,781	$	63,471	$	43,752
Comprehensive income	$	48,782	$	17,781	$	63,471	$	43,752
Basic income per share:
Income from continuing operations	$	1.18	$	0.44	$	1.47	$	1.09
Income from discontinued operations	$	—	$	—	$	0.09	$	—
Net income per common share	$	1.18	$	0.44	$	1.56	$	1.09
Diluted income per share:
Income from continuing operations	$	1.18	$	0.44	$	1.46	$	1.09
Income from discontinued operations	$	—	$	—	$	0.09	$	—
Net income per common share	$	1.18	$	0.44	$	1.55	$	1.09
Basic weighted-average common shares outstanding		40,556		39,356		39,958		39,315
Diluted weighted-average common shares outstanding		40,708		39,375		40,105		39,349

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

4

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Nine Months Ended September 30,
	2014		2013
	(in thousands)
Cash flows from operating activities:
Net income	$	63,471	$	43,752
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		158,557		89,897
Deferred income taxes		39,369		27,402
Stock-based compensation		17,312		9,716
Amortization of deferred financing costs		1,953		1,120
Amortization of premium on Senior Notes		(921)		—
Accretion of contractual obligation for land acquisition		571		571
Derivative (gain) loss		(14,761)		14,443
Abandoned lease		—		1,688
Gain on sale of oil and gas properties		(6,213)		—
Other		(12)		—
Changes in current assets and liabilities:
Accounts receivable		(23,837)		(32,081)
Prepaid expenses and other assets		(2,286)		726
Accounts payable and accrued liabilities		43,133		33,961
Settlement of asset retirement obligations		(374)		(73)
Net cash provided by operating activities		275,962		191,122
Cash flows from investing activities:
Acquisition of oil and gas properties		(178,883)		(10,969)
Proceeds from sale of oil and gas properties		6,000		—
Payments of contractual obligations		(12,000)		(12,000)
Exploration and development of oil and gas properties		(448,586)		(306,685)
Natural gas plant capital expenditures		(281)		(4,459)
Derivative cash settlements		(9,136)		(9,867)
(Increase) decrease in restricted cash		(3,062)		79
Additions to property and equipment - non oil and gas		(5,451)		(3,695)
Net cash used in investing activities		(651,399)		(347,596)
Cash flows from financing activities:
Proceeds from credit facility		230,000		72,000
Payments to credit facility		(230,000)		(191,500)
Proceeds from sale of Senior Notes		300,000		300,000
Offering costs related to sale of Senior Notes		(6,867)		(7,343)
Payment of employee tax withholdings in exchange for the return of common stock		(5,319)		(3,503)
Deferred financing costs		(341)		(79)
Net cash provided by financing activities		287,473		169,575
Net change in cash and cash equivalents		(87,964)		13,101
Cash and cash equivalents:
Beginning of period		180,582		4,268
End of period	$	92,618	$	17,369
Supplemental cash flow disclosure:
Cash paid for interest	$	18,519	$	2,855
Stock issued for the acquisition of oil and gas properties	$	49,050	$	—
Cash paid for income taxes	$	200	$	100
Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition	$	26,776	$	12,066

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

5

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

NOTE 1 - ORGANIZATION AND BUSINESS

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

NOTE 2 - BASIS OF PRESENTATION

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information. The quarterly financial statements included herein do not necessarily include all of the disclosures as may be required under generally accepted accounting principles for complete financial statements. There has been no material change in the information disclosed in the notes to the consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 (the “2013 Form 10-K”), except as disclosed herein. These consolidated financial statements include all of the adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and results of operations. All such adjustments are of a normal recurring nature only. The results of operations for the quarterly periods are not necessarily indicative of the results to be expected for the full fiscal year. The Company evaluated events subsequent to the balance sheet date of September 30, 2014, through the filing date of this report. Certain prior period amounts are reclassified to conform to the current period presentation, when necessary.

Principles of Consolidation

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

Significant Accounting Policies

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

Recently Issued Accounting Standards

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Update No. 2014-08  -Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The update is aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have or will have a major effect on an entity’s operations and financial results. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2014 and is to be applied prospectively. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures.

In May 2014, the FASB issued Update No. 2014-09  - Revenue From Contracts With Customers. The update prescribes two acceptable methods and is effective for the annual period beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

In June 2014, the FASB issued Update No. 2014-12 - Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved after the Requisite Service Period. The guidance relates to the recognition of share-based compensation when an award provides that a performance target can be achieved after the requisite service period. This authoritative accounting guidance may be applied either prospectively or retrospectively and is effective for annual periods and interim periods beginning after December 15, 2015. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

6

In August 2014, the FASB issued Update No. 2014-15 - Presentation of Financial Statements – Going Concern that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date that the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

NOTE 3 - ACQUISITIONS

The Company acquired approximately 86,000 gross (34,000 net) acres of oil and gas properties, leasehold mineral interests and related assets located in the Wattenberg Field (“Wattenberg Field Acquisition”) from a private operator. The Company paid approximately $174.6 million (inclusive of customary acquisition costs) in cash and issued 853,492 shares of the Company’s common stock valued at $57.47 per share, the market price at the time of closing, for the acquired assets. The Wattenberg Field Acquisition had an effective date of June 1, 2014 and closed on July 8, 2014. The results of operations for the Wattenberg Field Acquisition have been included in the Company’s condensed consolidated financial statements from the date of closing. Pro forma information is not presented as the pro forma results would not have been materially different from the information presented in the accompanying condensed consolidated statements of operations and comprehensive income (the “accompanying statements of operations”).

The Wattenberg Field Acquisition was recorded using the purchase method of accounting. The initial purchase price will be adjusted for post-closing settlements. The following table summarizes the allocation of consideration paid (inclusive of customary acquisition costs) to the tangible assets acquired and liabilities assumed in the Wattenberg Field Acquisition.

		Asset Valuation Amount
		(in thousands)
Purchase price	$	223,650
Allocation of purchase price:
Proved properties	$	25,014
Unproved properties		198,729
Asset retirement obligation		(93)
Total	$	223,650

NOTE 4 - DISCONTINUED OPERATIONS

During June 2012, the Company began marketing, with intent to sell, all of its oil and gas properties in California classifying them as assets held for sale. Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. The Company determined that its intent to sell all of its assets in a region qualified as discontinued operations. The Company sold its remaining property in this region during the first quarter of 2014 for approximately $6.0 million and recorded a gain on the sale of oil and gas properties in the amount of $6.2 million. The carrying amounts of the remaining properties included within assets held for sale classified as discontinued operations are presented below.

	As of September 30,		As of December 31,
	2014		2013
	(in thousands)
Oil and gas properties, successful efforts method:
Proved properties	$	—	$	1,721
Unproved properties		—		1
Wells in progress		—		101
Total property and equipment		—		1,823
Less accumulated depreciation, depletion and amortization		—		(1,463)
Property and equipment, net	$	—	$	360

7

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands)
Net revenues:
Oil and gas sales	$	—	$	403	$	361	$	1,278
Operating expenses:
Lease operating		—		574		366		1,479
Severance and ad valorem taxes		—		—		12		1
Exploration		—		1		—		66
Depreciation, depletion and amortization		—		62		68		267
Total operating expenses				637		446		1,813
Loss from operations associated with oil and gas properties held for sale	$	—	$	(234)	$	(85)	$	(535)

NOTE 5 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses contain the following:

	As of September 30,		As of December 31,
	2014		2013
	(in thousands)
Drilling and completion costs	$	107,747	$	80,971
Accounts payable trade		7,269		3,288
Accrued general and administrative cost		12,875		12,720
Lease operating expenses		6,339		5,440
Accrued reclamation cost		162		168
Accrued interest		18,940		7,065
Accrued oil and gas derivatives		—		446
Production and ad valorem taxes and other		19,236		11,567
Total accounts payable and accrued expenses	$	172,568	$	121,665

NOTE 6 -LONG-TERM DEBT

Credit Facility

The Company’s senior secured revolving Credit Agreement (the “Revolver” or “credit facility”), dated March 29, 2011, as amended, was further amended on September 30, 2014,to increase the borrowing base from $450 million (decreased from $525 millionfollowing the July 2014 issuance of the Company’s 5.75% Senior Notes) to $600 million. Thecredit facility has an aggregatepotential borrowing amount of $1 billion. The Company elected to limit bank commitments to $500 million while reserving the option to access, at the Company’s request, the full $600 million borrowing base prior to the next semi-annual redetermination on May 15, 2015. The Revolver is collateralized by substantially all of the Company’s assets and matures on September 15, 2018. As of September 30, 2014 and December 31, 2013, the Company had no outstanding balance under the Revolver with an available borrowing capacity of $576 million and $414 million, respectively, after the reduction of the outstanding letter of credit of $24 million and $36 million, respectively.

The Revolver restricts, among other items, the payment of dividends, certain additional indebtedness, sales of assets, loans and certain investments and mergers. The Revolver also contains certain financial covenants, which require the maintenance of minimum current and debt coverage ratios. The Company was in compliance with all financial and non-financial covenants as of September 30, 2014 and through the filing date of this report.

5.75% Senior Notes

8

On July 15, 2014, the Company issued $300 million aggregate principal amount of 5.75% Senior Notes (the “5.75% Senior Notes”) that mature on February 1, 2023. Interest on the 5.75% Senior Notes began accruing on July 15, 2014, and interestis payable on February 1 and August 1 of each year, beginning on February 1, 2015. The 5.75% 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 Revolver. The net proceeds from the sale of the 5.75% Senior Notes were $293.4 million after deductions of $6.6 million of expenses and underwriting discounts and commissions. The net proceeds were used to pay off the Company’s outstanding credit facility balance and the remainderwill be used for general corporate purposes, which may include funding the drilling and development program and other capital expenditures.

At any time prior to August 1, 2017, subject to certain limitations, the Company may redeem up to 35% of the aggregate principal amount of the 5.75% Senior Notes at a redemption price of 105.75% of the principal amount, plus accrued and unpaid interest, with an amount of cash not greater than the net cash proceeds of an equity offering. The Company may redeem all or a part of the 5.75% Senior Notes at any time prior to August 1, 2018 subject to a “make-whole” premium and accrued and unpaid interest. On or after August 1, 2018, the Company may redeem all or a part of the 5.75% Senior Notes at the redemption price of 102.875% for 2018, 101.438% for 2019, and 100.0% for 2020 and thereafter, during the twelve month period beginning on August 1 of each applicable year, in each case, plus accrued and unpaid interest.

As of September 30, 2014, and through the filing date of this report, all of the existing subsidiaries of the Company are guarantors of the 5.75% Senior Notes, and all such subsidiaries are 100% 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.

NOTE 7 - COMMITMENTS AND CONTINGENT LIABILITIES

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

Commitments

On October 1, 2014, the Company entered into a purchase and transportation agreement to deliver a fixed determinable quantity of crude oil currently anticipated to take effect during the third quarter of 2016. The minimum quantity commitment of crude oil is 15,000 barrels per day over an initial seven year term which equates to an aggregate financial commitment of approximately $322 million over the initial term. While the volume commitment may be met with Company volumes or third party volumes delegated by the Company, the Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments.  

On October 8,2014, the Company entered into a purchase and transportation agreement to deliver a fixed determinable quantity of crude oil currently anticipated to take effect during the first quarter of 2015. The minimum quantity commitment of crude oil is 12,580 barrels per day over an initial five year term which equates to an aggregate financial commitment of approximately $218 million over the initial term. While the volume commitment may be met with Company volumes or third party volumes delegated by the Company, the Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments.

9

NOTE 8 - STOCK-BASED COMPENSATION

Restricted Stock under the Long Term Incentive Plan

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

During the nine months ended September 30, 2014, the Company granted 228,818 shares of restricted stock under the Company’s Long Term Incentive Program (“LTIP”) to certain employees. The fair value of the issuance was $11.6 million. Total expense recorded for restricted stock for the three month periods ended September 30, 2014 and 2013, was $2.6 million and $2.5 million, respectively, and $15.8 million and $9.2 million for the nine months ended September 30, 2014 and 2013, respectively. As of September 30, 2014, unrecognized compensation cost was $1 million and will be amortized through 2017.

During the nine months ended September 30, 2014, the Company issued 9,416 shares of restricted common stock under the LTIP to its non-employee directors. Total expense recorded for non-employee directors for the three month periods ended September 30, 2014 and 2013, was $140,000 and $86,000, respectively and $545,000 and $258,000 for the nine months ended September 30, 2014 and 2013, respectively. These awards vest approximately one year after issuance.

A summary of the status and activity of non-vested restricted stock for the nine months ended September 30, 2014 is presented below:

		Weighted-
		Average
	Restricted	Grant-Date
	Stock	Fair Value
Non-vested at beginning of year	836,002	$	25.11
Granted	238,234	$	48.81
Vested	(455,878)	$	25.84
Forfeited	(25,229)	$	29.11
Non-vested at end of quarter	593,129	$	34.81

Performance Stock Units under the Long Term Incentive Plan

The Company grants performance stock units (“PSUs”) under the LTIP to certain officers of the Company. The number of shares of the Company’s common stock that may be issued to settle PSUs range from zero to two times the number of PSUs awarded. PSUs granted prior to 2014 are determined based on the Company’s performance over a three-year measurement period and vest in their entirety at the end of the measurement period. Satisfaction of the performance conditions for the PSUs granted during 2014 are determined at the end of each annual measurement period over the course of the three-year performance cycle in an amount up to two-thirds of the target number of PSUs that are eligible for vesting (such that an amount equal to 200% of the target number of PSUs may be earned during the performance cycle). For all grants, the PSUs will be settled in shares following the end of the three-year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited.

During the nine months ended September 30, 2014, the Company granted 63,766 PSUs under the LTIP to certain officers. The fair value of the issuance was $2.7 million. Total expense recorded for PSUs for the three month periods ended September 30, 2014 and 2013 was $392,000 and $102,000, respectively and $1.0 million and $209,000 for the nine month periods ended September 30, 2014 and 2013, respectively. As of September 30, 2014, there was $3.0 million of total unrecognized compensation expense related to unvested PSUs to be amortized through 2016.

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A summary of the status and activity of PSUs for the nine months ended September 30, 2014 is presented below:

		Weighted-Average
		Grant-Date
	PSU	Fair Value
Non-vested at beginning of year (1)	40,191	$	32.05
Granted(1)	63,766	$	42.50
Vested(1)	—	$	—
Forfeited(1)	—	$	—
Non-vested at end of quarter(1)	103,957	$	38.46

(1) The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition.

NOTE 9 - FAIR VALUE MEASUREMENTS

The Company follows fair value measurement authoritative guidance for all assets and liabilities measured at fair value, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A hierarchy for inputs is used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

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

Level 2:Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

Level 3:Significant inputs to the valuation model are unobservable

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

The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2014 and December 31, 2013 and their classification within the fair value hierarchy:

	As of September 30, 2014
	Level 1		Level 2		Level 3
	(in thousands)
Derivative assets	$	—	$	18,524	$	—
Derivative liabilities	$	—	$	—	$	—

	As of December 31, 2013
	Level 1		Level 2		Level 3
	(in thousands)
Derivative assets	$	—	$	1,151	$	—
Derivative liabilities	$	—	$	6,523	$	—

Derivatives

Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’s commodity swaps and collars 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

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valuation hierarchy. Presently, all of our derivative arrangements are concentrated with five counterparties all of which are lenders under the Company’s Revolver.

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. Management believes that the discount rate is representative of current market conditions and reflects the following factors: estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on the NYMEX strip pricing, adjusted for basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. There were no proved properties measured at fair value at September 30, 2014 or December 31, 2013.

Unproved Oil and Gas Properties

Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses Level 3 inputs and the income valuation technique, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, and estimated reserve values. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company uses the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. There were no unproved properties measured at fair value as of September 30, 2014 or December 31, 2013.

Asset Retirement Obligation

The Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Upon completion of wells and natural gas plants, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.  There were no asset retirement obligations measured at fair value at September 30, 2014 or December 31, 2013.

Long-term Debt

As of September 30, 2014, the Company had $500 million of outstanding 6.75% Senior Notes (the “6.75% Senior Notes”) and $300 million of outstanding 5.75% Senior Notes. The 6.75% Senior Notes are recorded at cost net of the unamortized premium on the accompanying balance sheets at $507.9 million and $508.8 million as of September 30, 2014 and December 31, 2013, respectively. The fair value of the 6.75%  Senior Notesas of September 30, 2014 and December 31, 2013 was $515.0 million and $527.5 million, respectively.The fair value of the 5.75% Senior Notes as of September 30, 2014 was $294.0 million. The Senior Notes are measured using Level 1 inputs based on a secondary market trading price.The Company’s Revolver, when drawn upon, approximates fair value as the applicable interest rates are floating.

NOTE 10 - DERIVATIVES

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

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As of September 30, 2014, and as of the filing date of this report, the Company had the following derivative commodity contracts in place:

		Total Volumes			Average		Average		Average		Fair Market
Settlement	Derivative	(Bbls/MMBtu	Average Fixed		Short Floor		Floor		Ceiling		Value of Asset
Period	Instrument	per day)	Price		Price		Price		Price		(Liability)
											(in thousands)
Oil
4Q 2014	Swap	6,370	$	95.62								3,166
1Q 2015	Swap	6,000	$	95.39								3,481
2Q 2015	Swap	5,000	$	94.21								2,940
3Q 2015	Swap	2,000	$	93.43								1,131
4Q 2015	Swap	2,000	$	93.43								1,177
4Q 2014	Collar	4,326					$	86.16	$	96.57		280
4Q 2014	3-Way Collar	2,000			$	65.00	$	87.68	$	99.75		249
1Q 2015	3-Way Collar	6,500			$	68.08	$	84.32	$	95.90		302
2Q 2015	3-Way Collar	5,500			$	67.73	$	84.09	$	95.16		321
3Q 2015	3-Way Collar	6,500			$	68.46	$	84.62	$	95.49		655
4Q 2015	3-Way Collar	6,500			$	68.46	$	84.62	$	95.49		660
1Q 2016	3-Way Collar	5,500			$	70.00	$	85.00	$	96.83		853
2Q 2016	3-Way Collar	5,500			$	70.00	$	85.00	$	96.83		856
3Q 2016	3-Way Collar	5,500			$	70.00	$	85.00	$	96.83		875
4Q 2016	3-Way Collar	5,500			$	70.00	$	85.00	$	96.83		789
											$	17,735
Gas
4Q 2014	3-Way Collar	30,000			$	3.63	$	4.21	$	4.81	$	496
1Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	(48)
2Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	190
3Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	137
4Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	14
											$	789
Total											$	18,524

Derivative Assets and Liabilities Fair Value

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

The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of September 30, 2014 and December 31, 2013:

	As of September 30, 2014
	Balance Sheet Location	Fair Value
		(in thousands)
Derivative Assets:
Commodity contracts	Current assets	$	13,300
Commodity contracts	Noncurrent assets		5,224
Derivative Liabilities:
Commodity contracts	Current liabilities		—
Commodity contracts	Long-term liabilities		—
Total net derivative asset		$	18,524

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

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

	Three months ended  September 30,					Nine months ended September 30,
	2014		2013			2014		2013
	(in thousands)					(in thousands)
Derivative cash settlement gain (loss):
Oil contracts	$	(1,577)		$	(6,962)	$	(9,171)	$	(10,206)
Gas contracts		583			88		35		339
Total derivative cash settlement (loss)(1)	$	(994)		$	(6,874)	$	(9,136)	$	(9,867)
Change in fair value gain (loss)	$	51,840		$	(10,016)	$	23,897	$	(4,576)
Total derivative gain (loss)(2)	$	50,846		$	(16,890)	$	14,761	$	(14,443)

(1) Derivative cash settlement gain (loss) for the nine monthsended September 30, 2014 and 2013 is reported in the derivative cash settlements line item on the accompanying condensed consolidated statements of cash flows  (the “statements of cash flows”) within the net cash used in investing activities.

(2) Total derivative gain (loss) for the nine months ended September 30, 2014 and 2013 is reported in the derivative gain (loss) line item on the accompanying statements of cash flows within the net cash provided by operating activities.

NOTE 11 - EARNINGS PER SHARE

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

The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company’s common stock that range from 0% to 200% of the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs. Please refer to Note 8 - Stock-Based Compensation, for additional discussion.

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The following table sets forth the calculation of earnings per basic and diluted shares from continuing and discontinued operations for the threeand ninemonth periods ended September 30, 2014 and 2013:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands, except per share amounts)
Income from continuing operations:
Income from continuing operations	$	48,854	$	17,925	$	59,696	$	44,081
Less: undistributed earnings to unvested restricted stock		914		446		1,124		1,055
Undistributed earnings to common shareholders		47,940		17,479		58,572		43,026
Basic income per common share from continuing operations	$	1.18	$	0.44	$	1.47	$	1.09
Diluted income per common share from continuing operations	$	1.18	$	0.44	$	1.46	$	1.09
Income (loss) from discontinued operations:
Income (loss) from discontinued operations	$	(72)	$	(144)	$	3,775	$	(329)
Less: undistributed earnings to unvested restricted stock		(1)		(4)		71		(8)
Undistributed earnings (loss) to common shareholders		(71)		(140)		3,704		(321)
Basic income per common share from discontinued operations	$	0.00	$	0.00	$	0.09	$	0.00
Diluted income per common share from discontinued operations	$	0.00	$	0.00	$	0.09	$	0.00
Net income:
Net income	$	48,782	$	17,781	$	63,471	$	43,752
Less: undistributed earnings to unvested restricted stock		913		442		1,195		1,047
Undistributed earnings to common shareholders		47,869		17,339		62,276		42,705
Basic net income per common share	$	1.18	$	0.44	$	1.56	$	1.09
Diluted net income per common share	$	1.18	$	0.44	$	1.55	$	1.09
Weighted-average shares outstanding - basic		40,556		39,356		39,958		39,315
Add: dilutive effect of contingent PSUs		152		19		147		34
Weighted-average shares outstanding - diluted		40,708		39,375		40,105		39,349

The Company had no anti-dilutive shares for the three and nine month periods ended September 30, 2014 and 2013.

NOTE 12 - INCOME TAXES

The Company uses the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time. During the three and nine month periods ended September 30, 2014 and 2013 the effective tax rate was 38.4 % and 38.5%, respectively

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

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

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2013 (the “2013 Form 10-K”), 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 of 2011. Our shares of common stock are listed for trading on the NYSE under the symbol “BCEI.”

Our operations are focused in the Wattenberg Field in Colorado (Rocky Mountain region) and the Dorcheat Macedonia Field in Southern Arkansas (Mid-Continent region). The predictable, oil-weighted production profile of our Arkansas assets provides a strong cash flow base from which to develop our Wattenberg Field assets, principally the Niobrara and Codell formations in Colorado. Our corporate strategy is to create shareholder value by increasing production in our current assets, while opportunistically seeking strategic acquisitions in our core areas or other high return basins across the United States where we can apply our technical competencies of horizontal drilling and fracture stimulation. We maintain a high working interest in our properties, which allows us to control the pace and magnitude of our capital spending program. 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.

Financial and Operating Highlights

Our financial results and operational highlights for the third quarter of 2014 included:

· Net income of $48.8 million (including approximately $48.9 million from continuing operations), as compared with $17.8 million (including approximately $17.9 million from continuing operations) for the third quarter of 2013. The increase in net income is primarily due to derivative gains;

· Total liquidity of $668.6 million, consisting of a period-end cash balance plus funds available under our revolving credit facility, as compared with $272.9 million for the third quarter of 2013;

· Acquired approximately 86,000 (34,000 net) acres, leasehold mineral interests and related assets within the Wattenberg Field for approximately $223.7 million to increase our acreage position within the Rocky Mountain region and leverage current infrastructure and operational expertise;

· Increased the Company’s borrowing base under its revolving credit facility by $150 million to $600 million during the third quarter of 2014;

· Increased production by 44% to 2,346.4 MBoe in the third quarter of 2014 from 1,624.3 MBoe in the third quarter of 2013, with oil and NGL production representing 69% of total production; and

· Drilled and completed 27 gross (23.0 net) productive wells within our Rocky Mountain region and 12 gross (10.0 net) productive wells within our Mid-Continent region during the third quarter of 2014.

During the nine months ended September 30, 2014, we had the following financial and operational results:

· Cash flows provided by operating activities of $276.0 million, as compared with $191.1 million for the first three quarters of 2013; and

· Capital expenditures of $485.3 million, as compared with $331.4 million for the first three quarters of 2013.

Outlook for 2014

Because the global economic outlook and commodity price environment are uncertain, we have planned a flexible capital spending program. We increased our estimated total capital expenditures for 2014 by $55 million during the third quarter of 2014 to

16

be between approximately $630 million to $680 million, allocated approximately 87% to the horizontal development of the Niobrara and Codell formations in the Wattenberg Field and 13% to the vertical development of the Dorcheat Macedonia and McKamie Patton Fields in Southern Arkansas. Actual capital expenditures may fluctuate materially based on, among other things, market conditions, and the success of our drilling results as the year continues to progress and changes in the borrowing base under our revolving credit facility. This capital investment is expected to produce average production volumes of 23,200 Boe/d to 24,200 Boe/d in 2014, while maintaining a strong oil and liquids profile.

Results of Continuing Operations

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

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

	Three Months Ended September 30,
							Percent
	2014		2013		Change		Change
	(In thousands, except percentages)
Revenues:
Crude oil sales	$	130,764	$	108,263	$	22,501	21	%
Natural gas sales		20,488		12,297		8,191	67	%
Natural gas liquids sales		5,119		5,387		(268)	-5	%
CO2 sales		—		26		(26)	(100)	%
Product revenue	$	156,371	$	125,973	$	30,398	24	%
Sales Volumes:
Crude oil (MBbls)		1,524.5		1,078.6		445.9	41	%
Natural gas (MMcf)		4,305.1		2,687.7		1,617.4	60	%
Natural gas liquids (MBbls)		104.4		97.7		6.7	7	%
Crude oil equivalent (MBoe)(1)		2,346.4		1,624.3		722.1	44	%
Average Sales Prices (before derivatives)(2)
Crude oil (per Bbl)	$	85.78	$	100.37	$	(14.59)	(15)	%
Natural gas (per Mcf)	$	4.76	$	4.58	$	0.18	4	%
Natural gas liquids (per Bbl)	$	49.03	$	55.14	$	(6.11)	(11)	%
Crude oil equivalent (per Boe)(1)	$	66.64	$	77.54	$	(10.90)	(14)	%
Average Sales Prices (after derivatives)(2)
Crude oil (per Bbl)	$	84.74	$	93.92	$	(9.18)	(10)	%
Natural gas (per Mcf)	$	4.89	$	4.61	$	0.28	6	%
Natural gas liquids (per Bbl)	$	49.03	$	55.14	$	(6.11)	(11)	%
Crude oil equivalent (per Boe)(1)	$	66.22	$	73.31	$	(7.09)	(10)	%

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

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

Revenues increased by 24%, to $156.4 million for the three months ended September 30, 2014 compared to $126.0 million for the three months ended September 30, 2013 due to an increase in oil, natural gas, and natural gas liquids production of 41%, 60%, and 7%, respectively, for the comparable period. The increased volumes were offset by a 14% decrease in crude oil equivalent pricing. The increased volumes are a direct result of the $115.7 million expended for drilling and completion during the last quarter of 2013 and the $485.3 million expended during the nine months ended September 30, 2014. During the period from September 30, 2013 through September 30, 2014, we drilled and completed 100 gross (87.1 net) wells in the Rocky Mountain region and 45 gross (35.9 net) wells in the Mid-Continent region. Our Wattenberg Field natural gas is sold as wet gas without processing into dry gas and NGLs, and therefore, sells at a premium due to its high BTU content.

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

	Three Months Ended September 30,
							Percent
	2014		2013		Change		Change
	(In thousands, except percentages)
Expenses:
Lease operating	$	18,217	$	12,958	$	5,259	41	%
Severance and ad valorem taxes		15,334		8,086		7,248	90	%
Exploration		3,291		2,099		1,192	57	%
Depreciation, depletion and amortization		63,241		36,750		26,491	72	%
General and administrative		14,814		13,811		1,003	7	%
Operating expenses	$	114,897	$	73,704	$	41,193	56	%
Selected Costs ($ per Boe):
Lease operating	$	7.76	$	7.98	$	(0.22)	(3)	%
Severance and ad valorem taxes		6.54		4.98		1.56	31	%
Exploration		1.40		1.29		0.11	9	%
Depreciation, depletion and amortization		26.95		22.63		4.32	19	%
General and administrative		6.31		8.50		(2.19)	(26)	%
Operating expenses	$	48.96	$	45.38	$	3.58	8	%

Lease Operating Expense.  Our lease operating expenses increased $5.2 million, or 41%, to $18.2 million for the three months ended September 30, 2014 from $13.0 million for the three months ended September 30, 2013 and decreased on an equivalent basis from $7.98 per Boe to $7.76 per Boe. The aggregate increase in lease operating expenses was related to increased production volumes attributable to our drilling program. During the quarter ended September 30, 2014, three of the largest components of lease operating expenses were well servicing, compression, and pumping which increased $1.8 million, $1.2 million and $754,000, respectively, over the comparable period in 2013. The decrease in lease operating expenses on an equivalent basis was primarily related to higher production from our horizontal wells in the Wattenberg Field.

Severance and ad valorem taxes.  Our severance and ad valorem taxes increased $7.2 million, or 90%, to $15.3 million for the three months ended September 30, 2014 from $8.1 million for the three months ended September 30, 2013. The increase was primarily related to a 44% increase in production volumes during the three months ended September 30, 2014 over the comparable period in 2013. Colorado has higher severance and ad valorem tax rates than Arkansas and contributed a greater percentage of production for the three months ended September 30, 2014 when compared to the same period in 2013. In addition, our increase in new production during 2013 in the Wattenberg Field resulted in a higher than expected lag in the amount of ad valorem tax credits eligible for deduction against severance taxes generated in the current year because ad valorem taxes are not eligible for deductionthe first year a well is completed.

Exploration.  Our exploration expense increased $1.2 million to $3.3 million during the three months ended September 30, 2014 from $2.1 million for the three months ended September 30, 2013. During the three months ended September 30, 2014 a seismic project in the DJ Basin was completed which resulted in charges of approximately $3.2 million. During the three months ended September 30, 2013, a $1.7 million non-core lease in the North Park Basin expired.

Depreciation, depletion and amortization.  Our depreciation, depletion, and amortization expense increased $26.5 million, or 72%, to $63.2 million for the three months ended September 30, 2014 from $36.7 million for the three months ended September 30, 2013. Our depreciation, depletion and amortization expense per Boe increased $4.32 or 19% to $26.95 for the three months ended September 30, 2014, as compared to $22.63 for the three months ended September 30, 2013. This increase was primarily the result of a larger increase in production of 44% versus the corresponding increase in proved developed reserves of 21%.

General and administrative. Our general and administrative expense increased $1.0 million, or 7%, to $14.8 million for the three months ended September 30, 2014 from $13.8 million for the comparable period in 2013 and decreased on an equivalent basis to $6.31 per Boe from $8.50 per Boe. During the three months ended September 30, 2014, wages and benefits, including bonuses, were $1.4 million higher than the same period in 2013. The increase in wages and benefits is due to an increase in headcount as a result of our drilling program between the three month periods ended September 30, 2014 and 2013. The decrease in general and administrative expense on an equivalent basis is due to production growth outpacing general and administrative expenses.

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Derivative gain (loss).  Our derivative gain increased $67.7 million to $50.8 million for the three month period ended September 30, 2014 from a $16.9 million loss for the comparable period in 2013. The gain incurred was primarily the result of realized prices being less than the contract prices as commodity strip prices, particularly oil, have decreased during the three months ended September 30, 2014. Please refer to Note 10 - Derivatives above for additional discussion.

Interest expense.  Our interest expense for the three months ended September 30, 2014 increased $7.0 million, or 113%, to $13.2 million compared to $6.2 million for the three months ended September 30, 2013. The increase for the three months ended September 30, 2014 is primarily due to the $200 million 6.75% Senior Note add-on that occurred during the fourth quarter of 2013 and the issuance of the $300 million 5.75% Senior Notes at the beginning of the third quarter of 2014. Interest expense, including amortization of the premium and financing costs, on the Senior Notes for the three month periods ended September 30, 2014 and 2013 was $12.2 million and $5.2 million, respectively. Average debt outstanding for the three months ended September 30, 2014 was $764.9 million as compared to $313.6 million for the comparable period in 2013.

Income tax expense. Our estimate for federal and state income taxes for the three months ended September 30, 2014 was $30.4 million from continuing operations as compared to $11.2 million for the three months ended September 30, 2013. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. Our effective tax rate for the three month periods ended September 30, 2014 and 2013 was 38.4% and 38.5%, respectively, which differs from the U.S. statutory income tax rate primarily due to the effects of state income taxes.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

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

	Nine Months Ended September 30,
							Percent
	2014		2013		Change		Change
	(In thousands, except percentages)
Revenues:
Crude oil sales	$	361,955	$	245,112	$	116,843	48	%
Natural gas sales		58,737		30,325		28,412	94	%
Natural gas liquids sales		14,749		13,269		1,480	11	%
CO2 sales		7		92		(85)	(92)	%
Product revenue	$	435,448	$	288,798	$	146,650	51	%
Sales Volumes:
Crude oil (MBbls)		4,065.1		2,599.9		1,465.2	56	%
Natural gas (MMcf)		11,091.4		6,648.2		4,443.2	67	%
Natural gas liquids (MBbls)		285.1		251.8		33.3	13	%
Crude oil equivalent (MBoe)(1)		6,198.8		3,959.7		2,239.1	57	%
Average Sales Prices (before derivatives)(2)
Crude oil (per Bbl)	$	89.04	$	94.28	$	(5.24)	(6)	%
Natural gas (per Mcf)	$	5.30	$	4.56	$	0.74	16	%
Natural gas liquids (per Bbl)	$	51.73	$	52.70	$	(0.97)	(2)	%
Crude oil equivalent (per Boe)(1)	$	70.25	$	72.91	$	(2.66)	(4)	%
Average Sales Prices (after derivatives)(2)
Crude oil (per Bbl)	$	86.78	$	90.35	$	(3.57)	(4)	%
Natural gas (per Mcf)	$	5.30	$	4.61	$	0.69	15	%
Natural gas liquids (per Bbl)	$	51.73	$	52.70	$	(0.97)	(2)	%
Crude oil equivalent (per Boe)(1)	$	68.77	$	70.42	$	(1.65)	(2)	%

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

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

Revenues increased by 51%, to $435.4 million for the nine months ended September 30, 2014 compared to $288.8 million for the nine months ended September 30, 2013 due primarily to the increase in oil, natural gas, and natural gas liquids production of 56%, 67%, and 13%, respectively, for the comparable periods. A decrease in average sales price on an equivalent basis of 4% for the nine months ended September 30, 2014 when compared to the same period in 2013 slightly offset the increase in production. Please refer to Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013 above for additional discussion.

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

	Nine Months Ended September 30,
							Percent
	2014		2013		Change		Change
	(In thousands, except percentages)
Expenses:
Lease operating	$	53,316	$	36,986	$	16,330	44	%
Severance and ad valorem taxes		42,347		18,251		24,096	132	%
Exploration		4,470		3,524		946	27	%
Depreciation, depletion and amortization		158,489		89,630		68,859	77	%
General and administrative		63,075		40,260		22,815	57	%
Operating expenses	$	321,697	$	188,651	$	133,046	71	%
Selected Costs ($ per Boe):
Lease operating	$	8.60	$	9.34	$	(0.74)	(8)	%
Severance and ad valorem taxes		6.83		4.61		2.22	48	%
Exploration		0.72		0.89		(0.17)	(19)	%
Depreciation, depletion and amortization		25.57		22.64		2.93	13	%
General and administrative		10.18		10.17		0.01	—	%
Operating expenses	$	51.90	$	47.65	$	4.25	9	%

Lease Operating Expense.  Our lease operating expenses increased $16.3 million, or 44%, to $53.3 million for the nine months ended September 30, 2014 from $37.0 million for the nine months ended September 30, 2013 and decreased on an equivalent basis from $9.34 per Boe to $8.60 per Boe. The aggregate increase in lease operating expenses was related to increased production volumes attributable to our drilling program. During the nine months ended September 30, 2014, three of the largest components of lease operating expenses were well servicing, compression, and pumping which increased $7.2 million, $3.8 million and $2.7 million, respectively, over the comparable period in 2013. The decrease in lease operating expenses on an equivalent basis was primarily related to higher production from our horizontal wells in the Wattenberg Field.

Severance and ad valorem taxes.  Our severance and ad valorem taxes increased $24.1 million, or 132%, to $42.3 million for the nine months ended September 30, 2014 from $18.2 million for the nine months ended September 30, 2013. The increase was primarily related to a 57% increase in production volumes during the nine months ended September 30, 2014 over the comparable period in 2013. Please refer to Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013 above for additional discussion.

Exploration.  Our exploration expense increased $946,000 to $4.5 million during the nine months ended September 30, 2014 from $3.5 million for the nine months ended September 30, 2013. During 2014, we incurred a $1.0 million dry hole charge related to a vertical well within the Wattenberg Field drilled to test the Lyons formation and incurred $3.2 million of seismic charges for an acquisition project within the Wattenberg Field. During 2013, a seismic acquisition project in the Wattenberg Field was completed which resulted in charges of approximately $1.4 million and a non-core lease for $1.7 million in the North Park Basin expired.

Depreciation, depletion and amortization.  Our depreciation, depletion, and amortization expense increased $68.9 million, or 77%, to $158.5 million for the nine months ended September 30, 2014 from $89.6 million for the nine months ended September 30, 2013. Our depreciation, depletion and amortization expense per Boe increased $2.93, or 13% to $25.57 for the nine months ended September 30, 2014 as compared to $22.64 for the nine months ended September 30, 2013. This increase is primarily due to a larger increase in production of 57% versus the corresponding increase in proved developed reserves of 21%.

General and administrative. Our general and administrative expense increased $22.8 million, or 57%, to $63.1 million for the nine months ended September 30, 2014 from $40.3 million for the comparable period in 2013 and slightly increased on an equivalent basis to $10.18 per Boe from $10.17 per Boe. During the nine months ended September 30, 2014, wages and benefits, including bonuses, were $9.6 million higher than the same period in 2013. Several executive departures in 2014 resulted in cash and stock-based severance of $14.1 million. Please refer to Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013 above for additional discussion.

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Derivative gain (loss).  Our derivative gain increased $29.2 million to $14.8 million for the nine month period ended September 30, 2014 from a $14.4 million loss for the comparable period in 2013. The gain incurred was primarily the result of realized prices being less than the contract prices. Please refer to Note 10 — Derivatives above for additional discussion.

Interest expense.  Our interest expense for the nine months ended September 30, 2014 increased $18.0 million, or 129%, to $32.0 million compared to $14.0 million for the nine months ended September 30, 2013. The increase for the nine months ended September 30, 2014 is primarily due to the $200 million 6.75% Senior Note add-on that occurred during the fourth quarter of 2013 and the issuance of the $300 million 5.75% Senior Notes at the beginning of the third quarter of 2014. Interest expense, including amortization of the premium and financing costs, on the Senior Notes for the nine month periods ended September 30, 2014 and 2013 was $29.2 million and $10.1 million, respectively. Interest expense on the revolving credit facility was $2.2 million and $3.4 million during the nine month periods ended September 30, 2014 and 2013, respectively. Average debt outstanding for the nine months ended September 30, 2014 was $593.0 million as compared to $262.1 million for the comparable period in 2013.

Income tax expense. Our estimate for federal and state income taxes for the nine months ended September 30, 2014 was $37.2 million from continuing operations as compared to $27.6 million for the nine months ended September 30, 2013. Our effective tax rate for the nine month periods ended September 30, 2014 and 2013 was 38.4% and 38.5%, respectively. Please refer to Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013 above for additional discussion.

Results for Discontinued Operations

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

The majority of these properties were sold in 2012. The remaining property located in the Midway Sunset Field sold on March 21, 2014 for approximately $6.0 million and resulted in a $6.2 million gain. Please refer to Note 4 — Discontinued Operations for additional discussion.

There were no operating results for our California properties for the three months ended September 30, 2014. Revenues and operating expenses for the same properties for the three months ended September 30, 2013 were $403,000 and $637,000, respectively. Sales volumes for the three month period ended September 30, 2013 were 41 Boe per day.

Revenues and operating expenses for the California properties for the nine months ended September 30, 2014 were $361,000 and $446,000, respectively. Revenues and operating expenses for the California properties for the nine months ended September 30, 2013 were $1.3 million and $1.8 million, respectively. Sales volumes for the nine month periods ended September 30, 2014 and 2013 were 13 Boe per day and 47 Boe per day.

Liquidity and Capital Resources

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

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

On May 15, 2014, our borrowing base under the revolving credit facility was increased to $525 million from $450 million. We elected to limit bank commitments to $400 million while reserving the option to access, at the Company’s request, the full $525 million. Upon issuance of our 5.75% Senior Notes on July 15, 2014, our borrowing base was adjusted down to $450 million. On September 30, 2014, our revolving credit facility was amended to increase our borrowing base to $600 million and we elected to limit our bank commitment to $500 million while reserving the option to access the full $600 million at the Company’s request. As of September 30, 2014, we had nil outstanding on our revolving credit facility, a $24 million letter of credit issued, and $576 million available borrowing capacity. Our weighted-average interest rate (excluding amortization of deferred financing costs and the accretion of our contractual obligation for land acquisition) on borrowings from our revolving credit facility was 2.06% and 2.27%,

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respectively, for the nine months ended September 30, 2014 and 2013.  Our commitment fees were $1.4 million and $1.3 million, respectively, for the nine months ended September 30, 2014 and 2013.

On July 15, 2014, we issued $300 million of 5.75% Senior Notes that mature on February 1, 2023. Interest on the 5.75% Senior Notes began accruing on July 15, 2014, and we will pay interest on February 1 and August 1 of each year, beginning on February 1, 2015. The net proceeds from the sale of the 5.75% Senior Notes were approximately $293.4 million after deductions of $6.6 million of expenses and underwriting discounts and commissions. The net proceeds were used to pay off the Company’s outstanding credit facility balance and the remainder will be used for general corporate purposes, which may include funding the drilling and development program and other capital expenditures.Please see Note 6 - Long-Term Debt above for additional discussion.

On July 8, 2014, we acquired approximately 86,000 gross (34,000 net) acres, leasehold mineral interests and related assets in the Wattenberg Field for approximately $223.7 million. We paid $174.6 million in cash and issued 853,492 shares of the Company’s common stock valued at $57.47 per share, the market price at the date of closing, for the acquired assets. The acquisition had an effective date of June 1, 2014 and allowed us to leverage our current infrastructure and technical expertise within the Rocky Mountain region. Please see Note 3 - Acquisitions above for additional discussion.

We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see Item 3. Quantitative and Qualitative Disclosures About Market Risks below and Note 10 -  Derivatives above for additional discussion.

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

	Nine Months Ended September 30,
	2014		2013
	(in thousands)
Net cash provided by operating activities	$	275,962	$	191,122
Net cash used in investing activities		(651,399)		(347,596)
Net cash provided by financing activities		287,473		169,575
Cash and cash equivalents		92,618		17,369
Acquisitions of oil and gas properties		178,883		10,969
Exploration and development of oil and gas properties and investment in gas processing facility, and obligation on land acquisition		460,868		323,144

Cash flows provided by operating activities

During the nine month period ended September 30, 2014, we generated $276.0  million of cash provided by operating activities, an increase of $84.8 million from the comparable period in 2013. The increase in cash flows from operating activities resulted primarily from a 57% increase in production. The increase in production was partially offset by increased lease operating expenses, production taxes, cash portion of general and administrative expense, and cash portion of interest expense during the nine month period ended September 30, 2014 as compared to the nine month period ended September 30, 2013. See Results of Continuing Operations above for more information on the factors driving these changes.

Cash flows used in investing activities

Expenditures for development of oil and natural gas properties and natural gas plants are the primary use of our capital resources. Net cash used in investing activities for the nine months ended September 30, 2014 increased $303.8 million inclusive of $6.0 million in proceeds received from the sale of the Midway Sunset property, compared to the same period in 2013. For the nine months ended September 30, 2014, cash used for the acquisition of oil and gas properties was $178.9 million and cash used for the development of oil and natural gas properties (including cash used for natural gas plant capital expenditures) was $448.9 million. For the nine months ended September 30, 2013, cash used for the acquisition of oil and gas properties was $11.0 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.

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Cash flows provided by financing activities

Net cash provided by financing activities for the nine months ended September 30, 2014 increased $117.9 million, compared to the same period in 2013. The increase is primarily due to the decrease in net repayments on our revolving credit facility of $119.5 million for the nine months ended September 30, 2014 when compared to the same period in 2013.

New Accounting Pronouncements

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

Critical Accounting Policies and Estimates

Information regarding our critical accounting policies and estimates is contained in Item 7 of our 2013 Form 10-K.

Effects of Inflation and Pricing

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the three and nine month periods ended September 30, 2014 and 2013. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations. Material changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base calculations, depletion expense, impairment assessments of oil and gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

Off-Balance Sheet Arrangements

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

Cautionary Note Regarding Forward-Looking Statements

This Report contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. When used in this Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” “plan,” “will,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

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

· reserves estimates;

· estimated production for 2014;

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

· ability to modify future capital expenditures;

· the Wattenberg Field being the most prospective area of the Niobrara formation;

· compliance with debt covenants;

· ability to satisfy obligations related to ongoing operations;

· compliance with government regulations;

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

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

· impact of lower commodity prices;

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

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

· loss of any purchaser of our products;

· our estimated revenues and losses;

· the timing and success of specific projects;

· intentions with respect to acquisitions and divestitures;

· intentions with respect to working interest percentages;

· management and technical team;

· outcomes and effects of litigation, claims and disputes;

· our business strategy;

· our ability to replace oil and natural gas reserves;

· impact of recently issued accounting pronouncements;

· our financial position;

· our cash flow and liquidity;

· our ability to leverage current infrastructure and our operational expertise to integrate and develop the Wattenberg Field Acquisition; and

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

We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences. Actual results could differ materially from those expressed or implied in the forward-looking statements.

Factors that could cause actual results to differ materially include, but are not limited to, the following:

· the risk factors discussed in Part I, Item 1A of our 2013 Form 10-K;

· 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;

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

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

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

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

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

· environmental risks;

· seasonal weather conditions and lease stipulations;

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

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

· availability of oilfield equipment, services and personnel;

· exploration and development risks;

· competition in the oil and natural gas industry;

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

· risks related to our derivative instruments;

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

· ability to maintain effective internal controls;

· access to adequate gathering systems and pipeline take-away capacity to provide adequate infrastructure for the products of our drilling program;

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

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

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

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

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

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Item 3.Quantitative and Qualitative Disclosures About Market Risk.

Oil and Natural Gas Prices

Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. Factors influencing oil and natural gas prices include the level of global demand for oil, the global supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels, the strength of the U.S. dollar compared to other currencies, and overall economic conditions. It is impossible to predict future oil and natural gas prices with any degree of certainty. Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically. Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and natural gas prices can have a favorable impact on our financial condition, results of operations and capital resources.

Commodity Derivative Contracts

Our primary commodity risk management objective is to reduce volatility in our cash flows. We enter into commodity derivative contracts for oil and natural gas using NYMEX futures or over-the-counter derivative financial instruments with counterparties who we believe are well-capitalized counterparties and who have been approved by our board of directors.

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

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

The result of oil market prices exceeding our swap prices or collar ceilings requires us to make payment for the settlement of our hedge derivatives, if owed by us, generally up to 15 business days before we receive market price cash payments from our customers. This could have a material adverse effect on our cash flows for the period between derivative settlement and payment for revenues earned.

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

Interest Rates

As of September 30, 2014, and on the filing date of this Report, we had no outstanding borrowings under our revolving credit facility, which is subject to floating market rates of interest. Borrowings under our revolving credit facility bear interest at a fluctuating rate that is tied to an adjusted base rate or LIBOR, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow.

Customer Credit Risk

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

Marketability of Our Production

The marketability of our production from the Mid-Continent and Rocky Mountain regions depends in part upon the availability, proximity and capacity of third-party refineries, access to regional trucking, pipeline and rail infrastructure, natural gas

26

gathering systems and processing facilities. We deliver crude oil and natural gas produced from these areas through trucking services, pipelines and rail facilities that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.

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

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

There have not been material changes to the interest rate risk analysis or oil and gas price sensitivity analysis disclosed in our 2013 Form 10-K.

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, 2014. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of September 30, 2014, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, not absolute, assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended September 30, 2014 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.Legal Proceedings.

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

Item 1A. Risk Factors.

Our business faces many risks. Any of the risk factors discussed in this Report or our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation. For a discussion of our potential risks and

27

uncertainties, see the information in Part I, Item 1A., Risk Factors, in our 2013 Form 10-K. There have been no material changes to our risk factors from those described in our 2013 Form 10-K.

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

Unregistered sales of securities. There were no sales of unregistered equity securities during the three month period ended September 30, 2014.

Issuer purchases of equity securities.  The following table contains information about our acquisition of equity securities during the three month period ended September 30, 2014.

					Maximum
				Total Number of	Number of
	Total			Shares	Shares that May
	Number of	Average Price		Purchased as Part of	Be Purchased
	Shares	Paid per		Publicly Announced	Under Plans or
	Purchased(1)	Share		Plans or Programs	Programs
July 1, 2014 — July 31, 2014	—	$	—	—	—
August 1, 2014 — August 31, 2014	5,330	$	55.26	—	—
September 1, 2014 — September 30, 2014	3,601	$	58.42	—	—
Total	8,931	$	56.53	—	—

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

A dividend payment, whether it be in the form of cash, securities or other property, is restricted by our revolving credit facilityand Senior Notes.

Item 3.Defaults Upon Senior Securities.

None.

Item 4.Mine Safety Disclosures.

Not applicable.

Item 5.Other Information

None.

Item 6.Exhibits.

28

Exhibit No.	Description of Exhibit
4.1	Registration Rights Agreement by and between DJ Resources, LLC and Bonanza Creek Energy, Inc. dated July 8, 2014 (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on July 11, 2014).
4.2	Indenture, dated July 18, 2014, among Bonanza Creek Energy, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on July 18, 2014).
4.3	First Supplemental Indenture, dated July 18, 2014, among Bonanza Creek Energy, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on July 18, 2014).
10.1	Amendment No. 10, dated as of September 30, 2014, to the Credit Agreement, among Bonanza Creek Energy, Inc., the Guarantors, KeyBank National Association, as Administrative Agent and as Issuing Lender, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 3, 2014).
31.1	Certification of the Principal Executive Officer pursuant to Rule 13a-14(a).
31.2	Certification of the Principal Financial Officer pursuant to Rule 13a-14(a).
32.1	Certification of the Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
32.2	Certification of the Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
101	The following materials from the Bonanza Creek Energy, Inc. Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, formatted in XBRL (Extensible Business Reporting Language) include (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Stockholders’ Equity, (iv) the Condensed Consolidated Statements of Cash Flows and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.

29

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		BONANZA CREEK ENERGY, INC.
Date:	November7, 2014	By:	/s/ Marvin M. Chronister
			Marvin M. Chronister
			Interim President and Chief Executive Officer
			(principal executive officer)
		By:	/s/ William J. Cassidy
			William J. Cassidy
			Executive Vice President and Chief Financial Officer
			(principal financial officer)
		By:	/s/ Wade E. Jaques
			Wade E. Jaques
			Vice President, Chief Accounting Officer
			(principal accounting officer)

30

EX-31.1

Exhibit 31.1

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

I, Marvin M. Chronister, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2014 of Bonanza Creek Energy, Inc.;

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

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

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

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

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date: November 7, 2014

/s/ Marvin M. Chronister

Marvin M. Chronister

Interim President and Chief Executive Officer

EX-31.2

Exhibit 31.2

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

I, William J. Cassidy, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2014 of Bonanza Creek Energy, Inc.;

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

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

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

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

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date: November 7, 2014

/s/ William J. Cassidy

William J. Cassidy

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification of the Chief Executive Officer

Pursuant to 18 U.S.C. Section 1350,

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

In connection with the Quarterly Report on Form10-Q of Bonanza Creek Energy, Inc. (the “Company”) for the period ended September30, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Marvin M. Chronister,Interim President and Chief Executive Officer of the Company, certify, pursuant to and solely for the purpose of 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

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

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

Date: November 7, 2014

/s/ Marvin M. Chronister

Marvin M. Chronister

Interim President and Chief Executive Officer

EX-32.2

Exhibit 32.2

Certification of the Chief Financial Officer

Pursuant to 18 U.S.C. Section 1350,

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

In connection with the Quarterly Report on Form10-Q of Bonanza Creek Energy, Inc. (the “Company”) for the period ended September30, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, William J. Cassidy, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

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

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

Date: November 7, 2014

/s/ William J. Cassidy

William J. Cassidy

Executive Vice President and Chief Financial Officer

XML

INCOME TAXES: (Details) (USD $)	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Reconciliation of effective tax rate to expected federal tax rate
Effective tax rate (as a percent)	38.40%	38.50%
Valuation allowances	$ 0

XML

FAIR VALUE MEASUREMENTS (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Financial assets and liabilities accounted for at fair value
Total number of counterparties in derivative financial instruments	5
Recurring | Level 2
Financial assets and liabilities accounted for at fair value
Derivative assets	$ 18,524	$ 1,151
Derivative liabilities		$ 6,523

XML

DERIVATIVES (Tables)

9 Months Ended

Sep. 30, 2014

DERIVATIVES

Summary of derivative commodity contracts in place

As of September 30, 2014, and as of the filing date of this report, the Company had the following derivative commodity contracts in place:

		Total Volumes			Average		Average		Average		Fair Market
Settlement	Derivative	(Bbls/MMBtu	Average Fixed		Short Floor		Floor		Ceiling		Value of Asset
Period	Instrument	per day)	Price		Price		Price		Price		(Liability)
											(in thousands)
Oil
4Q 2014	Swap	6,370	$	95.62								3,166
1Q 2015	Swap	6,000	$	95.39								3,481
2Q 2015	Swap	5,000	$	94.21								2,940
3Q 2015	Swap	2,000	$	93.43								1,131
4Q 2015	Swap	2,000	$	93.43								1,177
4Q 2014	Collar	4,326					$	86.16	$	96.57		280
4Q 2014	3-Way Collar	2,000			$	65.00	$	87.68	$	99.75		249
1Q 2015	3-Way Collar	6,500			$	68.08	$	84.32	$	95.90		302
2Q 2015	3-Way Collar	5,500			$	67.73	$	84.09	$	95.16		321
3Q 2015	3-Way Collar	6,500			$	68.46	$	84.62	$	95.49		655
4Q 2015	3-Way Collar	6,500			$	68.46	$	84.62	$	95.49		660
1Q 2016	3-Way Collar	5,500			$	70.00	$	85.00	$	96.83		853
2Q 2016	3-Way Collar	5,500			$	70.00	$	85.00	$	96.83		856
3Q 2016	3-Way Collar	5,500			$	70.00	$	85.00	$	96.83		875
4Q 2016	3-Way Collar	5,500			$	70.00	$	85.00	$	96.83		789
											$	17,735
Gas
4Q 2014	3-Way Collar	30,000			$	3.63	$	4.21	$	4.81	$	496
1Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	(48)
2Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	190
3Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	137
4Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	14
											$	789
Total											$	18,524

Summary of all the Company's derivative positions reported on the accompanying balance sheets

	As of September 30, 2014
	Balance Sheet Location	Fair Value
		(in thousands)
Derivative Assets:
Commodity contracts	Current assets	$	13,300
Commodity contracts	Noncurrent assets		5,224
Derivative Liabilities:
Commodity contracts	Current liabilities		—
Commodity contracts	Long-term liabilities		—
Total net derivative asset		$	18,524

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

Summary of the components of the derivative gain (loss) presented on the accompanying statements of operations

	Three months ended  September 30,					Nine months ended September 30,
	2014		2013			2014		2013
	(in thousands)					(in thousands)
Derivative cash settlement gain (loss):
Oil contracts	$	(1,577)		$	(6,962)	$	(9,171)	$	(10,206)
Gas contracts		583			88		35		339
Total derivative cash settlement (loss)(1)	$	(994)		$	(6,874)	$	(9,136)	$	(9,867)
Change in fair value gain (loss)	$	51,840		$	(10,016)	$	23,897	$	(4,576)
Total derivative gain (loss)(2)	$	50,846		$	(16,890)	$	14,761	$	(14,443)

(1) Derivative cash settlement gain (loss) for the nine monthsended September 30, 2014 and 2013 is reported in the derivative cash settlements line item on the accompanying condensed consolidated statements of cash flows (the “statements of cash flows”) within the net cash used in investing activities.

Total derivative gain (loss) for the nine months ended September 30, 2014 and 2013 is reported in the derivative gain (loss) line item on the accompanying statements of cash flows within the net cash provided by operating activities.

XML

DERIVATIVES (Details 3) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Components of the derivative gain (loss)
Derivative gain (loss)	$ 50,846	$ (16,890)	$ 14,761	$ (14,443)
Commodity derivative
Components of the derivative gain (loss)
Derivative cash settlement gain (loss)	(994)	(6,874)	(9,136)	(9,867)
Change in fair value gain (loss)	51,840	(10,016)	23,897	(4,576)
Derivative gain (loss)	50,846	(16,890)	14,761	(14,443)
Commodity derivative | Oil
Components of the derivative gain (loss)
Derivative cash settlement gain (loss)	(1,577)	(6,962)	(9,171)	(10,206)
Commodity derivative | Gas contracts
Components of the derivative gain (loss)
Derivative cash settlement gain (loss)	$ 583	$ 88	$ 35	$ 339

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ACQUISITIONS

9 Months Ended

Sep. 30, 2014

ACQUISITIONS

ACQUISITIONS

NOTE 3 - ACQUISITIONS

The Company acquired approximately 86,000 gross (34,000 net) acres of oil and gas properties, leasehold mineral interests and related assets located in the Wattenberg Field (“Wattenberg Field Acquisition”) from a private operator. The Company paid approximately $174.6 million (inclusive of customary acquisition costs) in cash and issued 853,492 shares of the Company’s common stock valued at $57.47 per share, the market price at the time of closing, for the acquired assets. The Wattenberg Field Acquisition had an effective date of June 1, 2014 and closed on July 8, 2014. The results of operations for the Wattenberg Field Acquisition have been included in the Company’s condensed consolidated financial statements from the date of closing. Pro forma information is not presented as the pro forma results would not have been materially different from the information presented in the accompanying condensed consolidated statements of operations and comprehensive income (the “accompanying statements of operations”).

The Wattenberg Field Acquisition was recorded using the purchase method of accounting. The initial purchase price will be adjusted for post-closing settlements. The following table summarizes the allocation of consideration paid (inclusive of customary acquisition costs) to the tangible assets acquired and liabilities assumed in the Wattenberg Field Acquisition.

		Asset Valuation Amount
		(in thousands)
Purchase price	$	223,650
Allocation of purchase price:
Proved properties	$	25,014
Unproved properties		198,729
Asset retirement obligation		(93)
Total	$	223,650

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ACCOUNTS PAYABLE AND ACCRUED EXPENSES (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Accounts payable and accrued expenses contain the following:
Drilling and completion costs	$ 107,747	$ 80,971
Accounts payable trade	7,269	3,288
Accrued general and administrative cost	12,875	12,720
Lease operating expense	6,339	5,440
Accrued reclamation cost	162	168
Accrued interest	18,940	7,065
Accrued oil and gas derivatives		446
Production and ad valorem taxes and other	19,236	11,567
Total accounts payable and accrued expenses	$ 172,568	$ 121,665

XML

DISCONTINUED OPERATIONS (Details) (USD $) In Thousands, unless otherwise specified	1 Months Ended	3 Months Ended			9 Months Ended
	Jun. 30, 2012	Sep. 30, 2014	Mar. 31, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
DISCONTINUED OPERATIONS
Period within which sale of asset takes place to classify it as held for sale	1 year
ACQUISTIONS AND DIVESTITURES
Proceeds from sale of oil and gas properties			$ 6,000		$ 6,000
Gain (loss) on sale of oil and gas properties		(117)	6,200		6,213
Oil and gas properties, successful efforts method:
Proved properties		1,753,604			1,753,604		1,257,288
Unproved properties		213,251			213,251		45,081
Wells in progress		155,096			155,096		110,848
Less accumulated depreciation, depletion and amortization		(377,733)			(377,733)		(224,848)
Net revenues:
Oil and gas sales		156,371		125,973	435,448	288,798
Operating expenses:
Lease operating expense		18,217		12,958	53,316	36,986
Severance and ad valorem taxes		15,334		8,086	42,347	18,251
Exploration		3,291		2,099	4,470	3,524
Depreciation, depletion and amortization		63,241		36,750	158,489	89,630
Total operating expenses		114,897		73,704	321,697	188,651
Loss from operations associated with oil and gas properties held for sale				(234)	(85)	(535)
Oil and gas properties in California
Oil and gas properties, successful efforts method:
Proved properties							1,721
Unproved properties							1
Wells in progress							101
Total property and equipment							1,823
Less accumulated depreciation, depletion and amortization							(1,463)
Net property and equipment							360
Net revenues:
Oil and gas sales				403	361	1,278
Operating expenses:
Lease operating expense				574	366	1,479
Severance and ad valorem taxes					12	1
Exploration				1		66
Depreciation, depletion and amortization				62	68	267
Total operating expenses				637	446	1,813
Loss from operations associated with oil and gas properties held for sale				$ (234)	$ (85)	$ (535)

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REVOLVING CREDIT FACILITY (Details) (USD $)				0 Months Ended	9 Months Ended		9 Months Ended
	Sep. 30, 2014 Revolver	Jul. 31, 2014 Revolver	Dec. 31, 2013 Revolver	Jul. 15, 2014 5.75% Senior Notes	Sep. 30, 2014 5.75% Senior Notes	Dec. 31, 2013 5.75% Senior Notes	Sep. 30, 2014 5.75% Senior Notes Prior to August 1, 2017	Sep. 30, 2014 5.75% Senior Notes 2018	Sep. 30, 2014 5.75% Senior Notes 2019	Sep. 30, 2014 5.75% Senior Notes 2020 and thereafter	Sep. 30, 2014 5.75% Senior Notes Maximum Prior to August 1, 2017
LONG-TERM DEBT
Maximum borrowing capacity	$ 1,000,000
Borrowing base	600,000,000
Bank commitments	500,000,000
Long-term debt	0		0
Remaining borrowing capacity	576,000,000		414,000,000
Letters of credit outstanding	24,000,000		36,000,000
Borrowing base before amendment	450,000,000	525,000,000
Amount of notes issued				300,000,000
Interest rate (as a percent)				5.75%	5.75%	5.75%
Redemption price as a percentage of principal amount of notes plus accrued and unpaid interest							105.75%
Net proceeds from sale of notes				293,400,000
Expenses and underwriting discounts and commissions				6,600,000
Percentage of principal amount redeemed								102.875%	101.438%	100.00%	35.00%
Ownership percentage in all existing subsidiaries					100.00%
Amount of independent assets other than ownership interest in subsidiaries and affiliates					0
Amount of independent operations other than ownership interest in subsidiaries and affiliates					$ 0

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COMMITMENTS AND CONTINGENT LIABILITIES (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended			9 Months Ended
	Oct. 08, 2014 bbl	Oct. 01, 2014	Oct. 01, 2014 bbl	Sep. 30, 2014 claim
COMMITMENTS AND CONTINGENT LIABILITIES
Number of Claims				0
Minimum commitment of crude oil	12,580		15,000
Term of commitment period	5 years		7 years
Total commitment	$ 218	$ 322

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BASIS OF PRESENTATION

9 Months Ended

Sep. 30, 2014

BASIS OF PRESENTATION

BASIS OF PRESENTATION

NOTE 2 - BASIS OF PRESENTATION

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information. The quarterly financial statements included herein do not necessarily include all of the disclosures as may be required under generally accepted accounting principles for complete financial statements. There has been no material change in the information disclosed in the notes to the consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 (the “2013 Form 10-K”), except as disclosed herein. These consolidated financial statements include all of the adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and results of operations. All such adjustments are of a normal recurring nature only. The results of operations for the quarterly periods are not necessarily indicative of the results to be expected for the full fiscal year. The Company evaluated events subsequent to the balance sheet date of September 30, 2014, through the filing date of this report. Certain prior period amounts are reclassified to conform to the current period presentation, when necessary.

Principles of Consolidation

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

Significant Accounting Policies

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

Recently Issued Accounting Standards

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Update No. 2014-08 -Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The update is aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have or will have a major effect on an entity’s operations and financial results. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2014 and is to be applied prospectively. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures.

In May 2014, the FASB issued Update No. 2014-09 - Revenue From Contracts With Customers. The update prescribes two acceptable methods and is effective for the annual period beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

In June 2014, the FASB issued Update No. 2014-12 - Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved after the Requisite Service Period. The guidance relates to the recognition of share-based compensation when an award provides that a performance target can be achieved after the requisite service period. This authoritative accounting guidance may be applied either prospectively or retrospectively and is effective for annual periods and interim periods beginning after December 15, 2015. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

In August 2014, the FASB issued Update No. 2014-15 - Presentation of Financial Statements – Going Concern that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date that the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

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STOCK-BASED COMPENSATION (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
STOCK-BASED COMPENSATION
Vesting period			3 years
Restricted Stock
Non-vested at beginning of year (in shares)			40,191
Granted (in shares)			63,766
Non-vested at end of year (in shares)	103,957		103,957
Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year (in dollars per share)			$ 32.05
Granted (in dollars per share)			$ 42.50
Non-vested at end of year (in dollars per share)	$ 38.46		$ 38.46
Shares granted			63,766
PSUs
Weighted-Average Grant-Date Fair Value
Vesting percent			66.67%
Percentage of awards earned during performance cycle			200.00%
PSUs | Minimum
Weighted-Average Grant-Date Fair Value
Ratio at which award holders get common stock of the company			0
PSUs | Maximum
Weighted-Average Grant-Date Fair Value
Ratio at which award holders get common stock of the company			200
2011 Long Term Incentive Plan | Restricted shares
STOCK-BASED COMPENSATION
Ratio of restricted stock to common stock to be released from restrictions upon completion of the vesting period			1
Vesting portion of shares			0.333
Restricted Stock
Non-vested at beginning of year (in shares)			836,002
Granted (in shares)			238,234
Vested (in shares)			(455,878)
Forfeited (in shares)			(25,229)
Non-vested at end of year (in shares)	593,129		593,129
Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year (in dollars per share)			$ 25.11
Granted (in dollars per share)			$ 48.81
Vested (in dollars per share)			$ 25.84
Forfeited (in dollars per share)			$ 29.11
Non-vested at end of year (in dollars per share)	$ 34.81		$ 34.81
Shares granted			238,234
2011 Long Term Incentive Plan | Restricted shares | Employees
STOCK-BASED COMPENSATION
Fair value of shares granted			$ 11,600,000
Stock-based compensation expense	2,600,000	2,500,000	15,800,000	9,200,000
Unrecognized compensation cost	1,000,000		1,000,000
Restricted Stock
Granted (in shares)			228,818
Weighted-Average Grant-Date Fair Value
Shares granted			228,818
2011 Long Term Incentive Plan | Restricted shares | Non-employee directors
STOCK-BASED COMPENSATION
Vesting period			1 year
Stock-based compensation expense	140,000	86,000	545,000	258,000
Restricted Stock
Granted (in shares)			9,416
Weighted-Average Grant-Date Fair Value
Shares granted			9,416
2011 Long Term Incentive Plan | PSUs | Minimum
Weighted-Average Grant-Date Fair Value
Ratio at which award holders get common stock of the company			0
2011 Long Term Incentive Plan | PSUs | Maximum
Weighted-Average Grant-Date Fair Value
Ratio at which award holders get common stock of the company			2
2011 Long Term Incentive Plan | PSUs | Officers
Weighted-Average Grant-Date Fair Value
Measurement period			3 years
2011 Long Term Incentive Plan | PSUs | Officers | Minimum
Weighted-Average Grant-Date Fair Value
Ratio at which award holders get common stock of the company			0
2011 Long Term Incentive Plan | PSUs | Officers | Maximum
Weighted-Average Grant-Date Fair Value
Ratio at which award holders get common stock of the company			2
2011 Long Term Incentive Plan | PSUs | Employees
STOCK-BASED COMPENSATION
Fair value of shares granted			2,700,000
Stock-based compensation expense	392,000	102,000	1.0	209,000
Unrecognized compensation cost	$ 3,000,000		$ 3,000,000
Restricted Stock
Granted (in shares)			63,766
Weighted-Average Grant-Date Fair Value
Shares granted			63,766

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 92,618	$ 180,582
Accounts receivable:
Oil and gas sales	72,292	57,485
Joint interest and other	21,945	12,915
Prepaid expenses and other	3,924	1,638
Inventory of oilfield equipment	9,996	10,696
Derivative asset	13,300	858
Total current assets	214,075	264,174
Property and equipment (successful efforts method), at cost:
Proved properties	1,753,604	1,257,288
Less: accumulated depreciation, depletion and amortization	(377,733)	(224,848)
Total proved properties, net	1,375,871	1,032,440
Unproved properties	213,251	45,081
Wells in progress	155,096	110,848
Natural gas plant, net of accumulated depreciation of $7,819 in 2014 and $5,903 in 2013	68,479	71,474
Other property and equipment, net of accumulated depreciation of $5,168 in 2014 and $2,822 in 2013	10,511	7,406
Oil and gas properties held for sale, net of accumulated depreciation, depletion, and amortization of $ - in 2014 and $1,463 in 2013 (Note 4)		360
Total property and equipment, net	1,823,208	1,267,609
Long-term derivative asset	5,224	293
Other noncurrent assets	23,724	13,859
Total assets	2,066,231	1,545,935
Current liabilities:
Accounts payable and accrued expenses (Note 5)	172,568	121,665
Oil and gas revenue distribution payable	45,951	36,241
Contractual obligation for land acquisition	12,000	12,000
Derivative liability		5,320
Total current liabilities	230,519	175,226
Long-term liabilities:
Contractual obligation for land acquisition	10,604	22,033
Ad valorem taxes	29,208	18,867
Derivative liability		1,203
Deferred income taxes, net	192,050	152,681
Asset retirement obligations	15,382	11,050
Total liabilities	1,285,689	889,907
Commitments and contingencies (Note 7)
Stockholders' equity:
Preferred stock, $.001 par value, 25,000,000 shares authorized, none outstanding
Common stock, $.001 par value, 225,000,000 shares authorized, 41,242,936 and 40,285,919 issued and outstanding in 2014 and 2013, respectively	41	40
Additional paid-in capital	588,794	527,752
Retained earnings	191,707	128,236
Total stockholders' equity	780,542	656,028
Total liabilities and stockholders' equity	2,066,231	1,545,935
6.75% Senior Notes
Long-term liabilities:
Senior Notes	507,926	508,847
5.75% Senior Notes
Long-term liabilities:
Senior Notes	$ 300,000

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Cash flows from operating activities:
Net income	$ 63,471	$ 43,752
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	158,557	89,897
Deferred income taxes	39,369	27,402
Stock-based compensation	17,312	9,716
Amortization of deferred financing costs	1,953	1,120
Amortization of premium on Senior Notes	(921)
Accretion of contractual obligation for land acquisition	571	571
Derivative (gain) loss	(14,761)	14,443
Abandoned lease		1,688
Gain on sale of oil and gas properties	(6,213)
Other	(12)
Changes in current assets and liabilities:
Accounts receivable	(23,837)	(32,081)
Prepaid expenses and other assets	(2,286)	726
Accounts payable and accrued liabilities	43,133	33,961
Settlement of asset retirement obligations	(374)	(73)
Net cash provided by operating activities	275,962	191,122
Cash flows from investing activities:
Acquisition of oil and gas properties	(178,883)	(10,969)
Proceeds from sale of oil and gas properties	6,000
Payments of contractual obligations	(12,000)	(12,000)
Exploration and development of oil and gas properties	(448,586)	(306,685)
Natural gas plant capital expenditures	(281)	(4,459)
Derivative cash settlements	(9,136)	(9,867)
(Increase) decrease in restricted cash	(3,062)	79
Additions to property and equipment - non oil and gas	(5,451)	(3,695)
Net cash used in investing activities	(651,399)	(347,596)
Payments of contractual obligations for land acquisition	(12,000)	(12,000)
Cash flows from financing activities:
Proceeds from credit facility	230,000	72,000
Payments to credit facility	(230,000)	(191,500)
Proceeds from sale of Senior Notes	300,000	300,000
Offering costs related to sale of Senior Notes	(6,867)	(7,343)
Payment of employee tax withholdings in exchange for the return of common stock	(5,319)	(3,503)
Deferred financing costs	(341)	(79)
Net cash provided by financing activities	287,473	169,575
Net change in cash and cash equivalents	(87,964)	13,101
Cash and cash equivalents:
Beginning of period	180,582	4,268
End of period	92,618	17,369
Supplemental cash flow disclosure:
Cash paid for interest	18,519	2,855
Stock issued for the acquisition of oil and gas properties	49,050
Cash paid for income taxes	200	100
Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition	$ 26,776	$ 12,066

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DERIVATIVES (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
DERIVATIVES
Number of derivative instruments qualified for hedging instruments	0
Commodity derivative
Derivative contract
Fair Value of Asset (Liability)	$ 18,524	$ (5,372)
Commodity derivative | Oil
Derivative contract
Fair Value of Asset (Liability)	17,735
Commodity derivative | Gas contracts
Derivative contract
Fair Value of Asset (Liability)	789
Commodity derivative | Swap | Oil
Derivative contract
Total Volumes (in units per day)	5,000
Average Fixed Price	94.21
Fair Value of Asset (Liability)	2,940
Commodity derivative | Swap | Oil | 4Q 2014
Derivative contract
Total Volumes (in units per day)	6,370
Average Fixed Price	95.62
Fair Value of Asset (Liability)	3,166
Commodity derivative | Swap | Oil | 1Q 2015
Derivative contract
Total Volumes (in units per day)	6,000
Average Fixed Price	95.39
Fair Value of Asset (Liability)	3,481
Commodity derivative | Swap | Oil | 3Q 2015
Derivative contract
Total Volumes (in units per day)	2,000
Average Fixed Price	93.43
Fair Value of Asset (Liability)	1,131
Commodity derivative | Swap | Oil | 4Q 2015
Derivative contract
Total Volumes (in units per day)	2,000
Average Fixed Price	93.43
Fair Value of Asset (Liability)	1,177
Commodity derivative | Collar | Oil | 4Q 2014
Derivative contract
Total Volumes (in units per day)	4,326
Average Floor Price	86.16
Average Ceiling Price	96.57
Fair Value of Asset (Liability)	280
Commodity derivative | 3-Way Collar | Oil | 4Q 2014
Derivative contract
Total Volumes (in units per day)	2,000
Average Short Floor Price	65.00
Average Floor Price	87.68
Average Ceiling Price	99.75
Fair Value of Asset (Liability)	249
Commodity derivative | 3-Way Collar | Oil | 1Q 2015
Derivative contract
Total Volumes (in units per day)	6,500
Average Short Floor Price	68.08
Average Floor Price	84.32
Average Ceiling Price	95.90
Fair Value of Asset (Liability)	302
Commodity derivative | 3-Way Collar | Oil | 2Q 2015
Derivative contract
Total Volumes (in units per day)	5,500
Average Short Floor Price	67.73
Average Floor Price	84.09
Average Ceiling Price	95.16
Fair Value of Asset (Liability)	321
Commodity derivative | 3-Way Collar | Oil | 3Q 2015
Derivative contract
Total Volumes (in units per day)	6,500
Average Short Floor Price	68.46
Average Floor Price	84.62
Average Ceiling Price	95.49
Fair Value of Asset (Liability)	655
Commodity derivative | 3-Way Collar | Oil | 4Q 2015
Derivative contract
Total Volumes (in units per day)	6,500
Average Short Floor Price	68.46
Average Floor Price	84.62
Average Ceiling Price	95.49
Fair Value of Asset (Liability)	660
Commodity derivative | 3-Way Collar | Oil | 1Q 2016
Derivative contract
Total Volumes (in units per day)	5,500
Average Short Floor Price	70.00
Average Floor Price	85.00
Average Ceiling Price	96.83
Fair Value of Asset (Liability)	853
Commodity derivative | 3-Way Collar | Oil | 2Q 2016
Derivative contract
Total Volumes (in units per day)	5,500
Average Short Floor Price	70.00
Average Floor Price	85.00
Average Ceiling Price	96.83
Fair Value of Asset (Liability)	856
Commodity derivative | 3-Way Collar | Oil | 3Q 2016
Derivative contract
Total Volumes (in units per day)	5,500
Average Short Floor Price	70.00
Average Floor Price	85.00
Average Ceiling Price	96.83
Fair Value of Asset (Liability)	875
Commodity derivative | 3-Way Collar | Oil | 4Q 2016
Derivative contract
Total Volumes (in units per day)	5,500
Average Short Floor Price	70.00
Average Floor Price	85.00
Average Ceiling Price	96.83
Fair Value of Asset (Liability)	789
Commodity derivative | 3-Way Collar | Gas contracts | 4Q 2014
Derivative contract
Total Volumes (in units per day)	30,000
Average Short Floor Price	3.63
Average Floor Price	4.21
Average Ceiling Price	4.81
Fair Value of Asset (Liability)	496
Commodity derivative | 3-Way Collar | Gas contracts | 1Q 2015
Derivative contract
Total Volumes (in units per day)	15,000
Average Short Floor Price	3.50
Average Floor Price	4.00
Average Ceiling Price	4.75
Fair Value of Asset (Liability)	(48)
Commodity derivative | 3-Way Collar | Gas contracts | 2Q 2015
Derivative contract
Total Volumes (in units per day)	15,000
Average Short Floor Price	3.50
Average Floor Price	4.00
Average Ceiling Price	4.75
Fair Value of Asset (Liability)	190
Commodity derivative | 3-Way Collar | Gas contracts | 3Q 2015
Derivative contract
Total Volumes (in units per day)	15,000
Average Short Floor Price	3.50
Average Floor Price	4.00
Average Ceiling Price	4.75
Fair Value of Asset (Liability)	137
Commodity derivative | 3-Way Collar | Gas contracts | 4Q 2015
Derivative contract
Total Volumes (in units per day)	15,000
Average Short Floor Price	3.50
Average Floor Price	4.00
Average Ceiling Price	4.75
Fair Value of Asset (Liability)	$ 14

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ACCOUNTS PAYABLE AND ACCRUED EXPENSES (Tables)

9 Months Ended

Sep. 30, 2014

ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Schedule of accounts payable and accrued expenses

	As of September 30,		As of December 31,
	2014		2013
	(in thousands)
Drilling and completion costs	$	107,747	$	80,971
Accounts payable trade		7,269		3,288
Accrued general and administrative cost		12,875		12,720
Lease operating expenses		6,339		5,440
Accrued reclamation cost		162		168
Accrued interest		18,940		7,065
Accrued oil and gas derivatives		—		446
Production and ad valorem taxes and other		19,236		11,567
Total accounts payable and accrued expenses	$	172,568	$	121,665

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DERIVATIVES (Details 2) (Commodity derivative, USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Derivatives measured at fair value
Total net derivative liability	$ 18,524	$ (5,372)
Current assets
Derivatives measured at fair value
Derivative Assets	13,300	858
Noncurrent assets
Derivatives measured at fair value
Derivative Assets	5,224	293
Current liabilities
Derivatives measured at fair value
Derivative Liabilities		(5,320)
Long-term liabilities
Derivatives measured at fair value
Derivative Liabilities		$ (1,203)

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FAIR VALUE MEASUREMENTS (Tables)

9 Months Ended

Sep. 30, 2014

FAIR VALUE MEASUREMENTS

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

	As of September 30, 2014
	Level 1		Level 2		Level 3
	(in thousands)
Derivative assets	$	—	$	18,524	$	—
Derivative liabilities	$	—	$	—	$	—

	As of December 31, 2013
	Level 1		Level 2		Level 3
	(in thousands)
Derivative assets	$	—	$	1,151	$	—
Derivative liabilities	$	—	$	6,523	$	—

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ORGANIZATION AND BUSINESS

9 Months Ended

Sep. 30, 2014

ORGANIZATION AND BUSINESS

ORGANIZATION AND BUSINESS

NOTE 1 - ORGANIZATION AND BUSINESS

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

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Sep. 30, 2014 Assets held for sale	Dec. 31, 2013 Assets held for sale
Natural gas plant, accumulated depreciation (in dollars)	$ 7,819	$ 5,903
Other property and equipment, accumulated depreciation (in dollars)	5,168	2,822
Oil and gas properties held for sale, accumulated depreciation, depletion, and amortization (note 3) (in dollars)	377,733	224,848		0	1,463
Senior Notes unamortized premium	$ 7,926		$ 8,847
Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized	25,000,000	25,000,000
Preferred stock, shares outstanding	0	0
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized	225,000,000	225,000,000
Common stock, shares issued	41,242,936	40,285,919
Common stock, shares outstanding	41,242,936	40,285,919

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EARNINGS PER SHARE

9 Months Ended

Sep. 30, 2014

EARNINGS PER SHARE

EARNINGS PER SHARE

NOTE 11 - EARNINGS PER SHARE

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

The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs, a number of shares of the Company’s common stock that range from 0% to 200% of the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs. Please refer to Note 8 - Stock-Based Compensation, for additional discussion.

The following table sets forth the calculation of earnings per basic and diluted shares from continuing and discontinued operations for the three and nine month periods ended September 30, 2014 and 2013:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands, except per share amounts)
Income from continuing operations:
Income from continuing operations	$	48,854	$	17,925	$	59,696	$	44,081
Less: undistributed earnings to unvested restricted stock		914		446		1,124		1,055
Undistributed earnings to common shareholders		47,940		17,479		58,572		43,026
Basic income per common share from continuing operations	$	1.18	$	0.44	$	1.47	$	1.09
Diluted income per common share from continuing operations	$	1.18	$	0.44	$	1.46	$	1.09
Income (loss) from discontinued operations:
Income (loss) from discontinued operations	$	(72)	$	(144)	$	3,775	$	(329)
Less: undistributed earnings to unvested restricted stock		(1)		(4)		71		(8)
Undistributed earnings (loss) to common shareholders		(71)		(140)		3,704		(321)
Basic income per common share from discontinued operations	$	0.00	$	0.00	$	0.09	$	0.00
Diluted income per common share from discontinued operations	$	0.00	$	0.00	$	0.09	$	0.00
Net income:
Net income	$	48,782	$	17,781	$	63,471	$	43,752
Less: undistributed earnings to unvested restricted stock		913		442		1,195		1,047
Undistributed earnings to common shareholders		47,869		17,339		62,276		42,705
Basic net income per common share	$	1.18	$	0.44	$	1.56	$	1.09
Diluted net income per common share	$	1.18	$	0.44	$	1.55	$	1.09
Weighted-average shares outstanding - basic		40,556		39,356		39,958		39,315
Add: dilutive effect of contingent PSUs		152		19		147		34
Weighted-average shares outstanding - diluted		40,708		39,375		40,105		39,349

The Company had no anti-dilutive shares for the three and nine month periods ended September 30, 2014 and 2013.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Nov. 03, 2014
Document and Entity Information
Entity Registrant Name	Bonanza Creek Energy, Inc.
Entity Central Index Key	0001509589
Document Type	10-Q
Document Period End Date	Sep. 30, 2014
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		41,237,932
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3

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INCOME TAXES:

9 Months Ended

Sep. 30, 2014

INCOME TAXES:

INCOME TAXES:

NOTE 12 - INCOME TAXES

The Company uses the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time. During the three and nine month periods ended September 30, 2014 and 2013 the effective tax rate was 38.4 % and 38.5%, respectively

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

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

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Operating net revenues:
Oil and gas sales	$ 156,371	$ 125,973	$ 435,448	$ 288,798
Operating expenses:
Lease operating	18,217	12,958	53,316	36,986
Severance and ad valorem taxes	15,334	8,086	42,347	18,251
Exploration	3,291	2,099	4,470	3,524
Depreciation, depletion and amortization	63,241	36,750	158,489	89,630
General and administrative (including $3,162, $2,652, $17,312, and $9,716, respectively, of stock-based compensation)	14,814	13,811	63,075	40,260
Total operating expenses	114,897	73,704	321,697	188,651
Income from operations	41,474	52,269	113,751	100,147
Other income (expense):
Derivative gain (loss)	50,846	(16,890)	14,761	(14,443)
Interest expense	(13,228)	(6,180)	(31,997)	(14,013)
Other income (loss)	181	(53)	397	(3)
Total other income (expense)	37,799	(23,123)	(16,839)	(28,459)
Income from continuing operations before taxes	79,273	29,146	96,912	71,688
Income tax expense	(30,419)	(11,221)	(37,216)	(27,607)
Income from continuing operations	48,854	17,925	59,696	44,081
Discontinued operations (Note 4)
Loss from operations associated with oil and gas properties held for sale		(234)	(85)	(535)
Gain (loss) on sale of oil and gas properties	(117)		6,213
Income tax (expense) benefit	45	90	(2,353)	206
Gain (loss) from discontinued operations	(72)	(144)	3,775	(329)
Net income	48,782	17,781	63,471	43,752
Comprehensive income	$ 48,782	$ 17,781	$ 63,471	$ 43,752
Basic income per share:
Income from continuing operations (in dollars per share)	$ 1.18	$ 0.44	$ 1.47	$ 1.09
Income from discontinued operations (in dollars per share)	$ 0.00	$ 0.00	$ 0.09	$ 0.00
Net income per common share (in dollars per share)	$ 1.18	$ 0.44	$ 1.56	$ 1.09
Diluted income per share:
Income from continuing operations (in dollars per share)	$ 1.18	$ 0.44	$ 1.46	$ 1.09
Income from discontinued operations (in dollars per share)	$ 0.00	$ 0.00	$ 0.09	$ 0.00
Net income per common share (in dollars per share)	$ 1.18	$ 0.44	$ 1.55	$ 1.09
Basic weighted-average common shares outstanding	40,556	39,356	39,958	39,315
Diluted weighted-average common shares outstanding	40,708	39,375	40,105	39,349

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REVOLVING CREDIT FACILITY

9 Months Ended

Sep. 30, 2014

REVOLVING CREDIT FACILITY

REVOLVING CREDIT FACILITY

NOTE 6 - LONG-TERM DEBT

Credit Facility

The Company’s senior secured revolving Credit Agreement (the “Revolver” or “credit facility”), dated March 29, 2011, as amended, was further amended on September 30, 2014, to increase the borrowing base from $450 million (decreased from $525 million following the July 2014 issuance of the Company’s 5.75% Senior Notes) to $600 million. The credit facility has an aggregate potential borrowing amount of $1 billion. The Company elected to limit bank commitments to $500 million while reserving the option to access, at the Company’s request, the full $600 million borrowing base prior to the next semi-annual redetermination on May 15, 2015. The Revolver is collateralized by substantially all of the Company’s assets and matures on September 15, 2018. As of September 30, 2014 and December 31, 2013, the Company had no outstanding balance under the Revolver with an available borrowing capacity of $576 million and $414 million, respectively, after the reduction of the outstanding letter of credit of $24 million and $36 million, respectively.

The Revolver restricts, among other items, the payment of dividends, certain additional indebtedness, sales of assets, loans and certain investments and mergers. The Revolver also contains certain financial covenants, which require the maintenance of minimum current and debt coverage ratios. The Company was in compliance with all financial and non-financial covenants as of September 30, 2014 and through the filing date of this report.

5.75% Senior Notes

On July 15, 2014, the Company issued $300 million aggregate principal amount of 5.75% Senior Notes (the “5.75% Senior Notes”) that mature on February 1, 2023. Interest on the 5.75% Senior Notes began accruing on July 15, 2014, and interest is payable on February 1 and August 1 of each year, beginning on February 1, 2015. The 5.75% 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 Revolver. The net proceeds from the sale of the 5.75% Senior Notes were $293.4 million after deductions of $6.6 million of expenses and underwriting discounts and commissions. The net proceeds were used to pay off the Company’s outstanding credit facility balance and the remainder will be used for general corporate purposes,  which may include funding the drilling and development program and other capital expenditures.

At any time prior to August 1, 2017, subject to certain limitations, the Company may redeem up to 35% of the aggregate principal amount of the 5.75% Senior Notes at a redemption price of 105.75% of the principal amount, plus accrued and unpaid interest, with an amount of cash not greater than the net cash proceeds of an equity offering. The Company may redeem all or a part of the 5.75% Senior Notes at any time prior to August 1, 2018 subject to a “make-whole” premium and accrued and unpaid interest. On or after August 1, 2018, the Company may redeem all or a part of the 5.75% Senior Notes at the redemption price of 102.875% for 2018, 101.438% for 2019, and 100.0% for 2020 and thereafter, during the twelve month period beginning on August 1 of each applicable year, in each case, plus accrued and unpaid interest.

As of September 30, 2014, and through the filing date of this report, all of the existing subsidiaries of the Company are guarantors of the 5.75% Senior Notes, and all such subsidiaries are 100% 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.

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ACCOUNTS PAYABLE AND ACCRUED EXPENSES

9 Months Ended

Sep. 30, 2014

ACCOUNTS PAYABLE AND ACCRUED EXPENSES

ACCOUNTS PAYABLE AND ACCRUED EXPENSES

NOTE 5 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses contain the following:

	As of September 30,		As of December 31,
	2014		2013
	(in thousands)
Drilling and completion costs	$	107,747	$	80,971
Accounts payable trade		7,269		3,288
Accrued general and administrative cost		12,875		12,720
Lease operating expenses		6,339		5,440
Accrued reclamation cost		162		168
Accrued interest		18,940		7,065
Accrued oil and gas derivatives		—		446
Production and ad valorem taxes and other		19,236		11,567
Total accounts payable and accrued expenses	$	172,568	$	121,665

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STOCK-BASED COMPENSATION (Tables)

9 Months Ended

Sep. 30, 2014

STOCK-BASED COMPENSATION

Summary of the status and activity of non-vested restricted stock

		Weighted-
		Average
	Restricted	Grant-Date
	Stock	Fair Value
Non-vested at beginning of year	836,002	$	25.11
Granted	238,234	$	48.81
Vested	(455,878)	$	25.84
Forfeited	(25,229)	$	29.11
Non-vested at end of quarter	593,129	$	34.81

Summary of the status and activity of PSUs

		Weighted-Average
		Grant-Date
	PSU	Fair Value
Non-vested at beginning of year (1)	40,191	$	32.05
Granted(1)	63,766	$	42.50
Vested(1)	—	$	—
Forfeited(1)	—	$	—
Non-vested at end of quarter(1)	103,957	$	38.46

The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition.

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BASIS OF PRESENTATION (Policies)

9 Months Ended

Sep. 30, 2014

BASIS OF PRESENTATION

Principles of Consolidation

Principles of Consolidation

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

Significant Accounting Policies

Significant Accounting Policies

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

Recently Issued Accounting Standards

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Update No. 2014-08 -Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The update is aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have or will have a major effect on an entity’s operations and financial results. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2014 and is to be applied prospectively. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures.

In May 2014, the FASB issued Update No. 2014-09 - Revenue From Contracts With Customers. The update prescribes two acceptable methods and is effective for the annual period beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

In June 2014, the FASB issued Update No. 2014-12 - Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved after the Requisite Service Period. The guidance relates to the recognition of share-based compensation when an award provides that a performance target can be achieved after the requisite service period. This authoritative accounting guidance may be applied either prospectively or retrospectively and is effective for annual periods and interim periods beginning after December 15, 2015. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

In August 2014, the FASB issued Update No. 2014-15 - Presentation of Financial Statements – Going Concern that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date that the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

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FAIR VALUE MEASUREMENTS

9 Months Ended

Sep. 30, 2014

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

NOTE 9 - FAIR VALUE MEASUREMENTS

The Company follows fair value measurement authoritative guidance for all assets and liabilities measured at fair value, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A hierarchy for inputs is used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

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

Level 2:Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

Level 3:Significant inputs to the valuation model are unobservable

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

The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2014 and December 31, 2013 and their classification within the fair value hierarchy:

	As of September 30, 2014
	Level 1		Level 2		Level 3
	(in thousands)
Derivative assets	$	—	$	18,524	$	—
Derivative liabilities	$	—	$	—	$	—

	As of December 31, 2013
	Level 1		Level 2		Level 3
	(in thousands)
Derivative assets	$	—	$	1,151	$	—
Derivative liabilities	$	—	$	6,523	$	—

Derivatives

Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’s commodity swaps and collars 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. Presently, all of our derivative arrangements are concentrated with five counterparties all of which are lenders under the Company’s Revolver.

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. Management believes that the discount rate is representative of current market conditions and reflects the following factors: estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on the NYMEX strip pricing, adjusted for basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. There were no proved properties measured at fair value at September 30, 2014 or December 31, 2013.

Unproved Oil and Gas Properties

Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses Level 3 inputs and the income valuation technique, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, and estimated reserve values. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company uses the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. There were no unproved properties measured at fair value as of September 30, 2014 or December 31, 2013.

Asset Retirement Obligation

The Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Upon completion of wells and natural gas plants, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.  There were no asset retirement obligations measured at fair value at September 30, 2014 or December 31, 2013.

Long-term Debt

As of September 30, 2014, the Company had $500 million of outstanding 6.75% Senior Notes (the “6.75% Senior Notes”) and $300 million of outstanding 5.75% Senior Notes. The 6.75% Senior Notes are recorded at cost net of the unamortized premium on the accompanying balance sheets at $507.9 million and $508.8 million as of September 30, 2014 and December 31, 2013, respectively. The fair value of the 6.75% Senior Notes as of September 30, 2014 and December 31, 2013 was $515.0 million and $527.5 million, respectively. The fair value of the 5.75% Senior Notes as of September 30, 2014 was $294.0 million. The Senior Notes are measured using Level 1 inputs based on a secondary market trading price. The Company’s Revolver, when drawn upon, approximates fair value as the applicable interest rates are floating.

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COMMITMENTS AND CONTINGENT LIABILITIES

9 Months Ended

Sep. 30, 2014

COMMITMENTS AND CONTINGENT LIABILITIES

COMMITMENTS AND CONTINGENT LIABILITIES

NOTE 7 - COMMITMENTS AND CONTINGENT LIABILITIES

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

Commitments

On October 1, 2014, the Company entered into a purchase and transportation agreement to deliver a fixed determinable quantity of crude oil currently anticipated to take effect during the third quarter of 2016. The minimum quantity commitment of crude oil is 15,000 barrels per day over an initial seven year term which equates to an aggregate financial commitment of approximately $322 million over the initial term. While the volume commitment may be met with Company volumes or third party volumes delegated by the Company, the Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments.

On October 8, 2014, the Company entered into a purchase and transportation agreement to deliver a fixed determinable quantity of crude oil currently anticipated to take effect during the first quarter of 2015. The minimum quantity commitment of crude oil is 12,580 barrels per day over an initial five year term which equates to an aggregate financial commitment of approximately $218 million over the initial term. While the volume commitment may be met with Company volumes or third party volumes delegated by the Company, the Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume commitments.

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STOCK-BASED COMPENSATION

9 Months Ended

Sep. 30, 2014

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION

NOTE 8 - STOCK-BASED COMPENSATION

Restricted Stock under the Long Term Incentive Plan

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

During the nine months ended September 30, 2014, the Company granted 228,818 shares of restricted stock under the Company’s Long Term Incentive Program (“LTIP”) to certain employees. The fair value of the issuance was $11.6 million. Total expense recorded for restricted stock for the three month periods ended September 30, 2014 and 2013, was $2.6 million and $2.5 million, respectively, and $15.8 million and $9.2 million for the nine months ended September 30, 2014 and 2013, respectively. As of September 30, 2014, unrecognized compensation cost was $1 million and will be amortized through 2017.

During the nine months ended September 30, 2014, the Company issued 9,416 shares of restricted common stock under the LTIP to its non-employee directors. Total expense recorded for non-employee directors for the three month periods ended September 30, 2014 and 2013, was $140,000 and $86,000, respectively and $545,000 and $258,000 for the nine months ended September 30, 2014 and 2013, respectively. These awards vest approximately one year after issuance.

A summary of the status and activity of non-vested restricted stock for the nine months ended September 30, 2014 is presented below:

		Weighted-
		Average
	Restricted	Grant-Date
	Stock	Fair Value
Non-vested at beginning of year	836,002	$	25.11
Granted	238,234	$	48.81
Vested	(455,878)	$	25.84
Forfeited	(25,229)	$	29.11
Non-vested at end of quarter	593,129	$	34.81

Performance Stock Units under the Long Term Incentive Plan

The Company grants performance stock units (“PSUs”) under the LTIP to certain officers of the Company. The number of shares of the Company’s common stock that may be issued to settle PSUs range from zero to two times the number of PSUs awarded. PSUs granted prior to 2014 are determined based on the Company’s performance over a three-year measurement period and vest in their entirety at the end of the measurement period. Satisfaction of the performance conditions for the PSUs granted during 2014 are determined at the end of each annual measurement period over the course of the three-year performance cycle in an amount up to two-thirds of the target number of PSUs that are eligible for vesting (such that an amount equal to 200% of the target number of PSUs may be earned during the performance cycle). For all grants, the PSUs will be settled in shares following the end of the three-year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited.

During the nine months ended September 30, 2014, the Company granted 63,766 PSUs under the LTIP to certain officers. The fair value of the issuance was $2.7 million. Total expense recorded for PSUs for the three month periods ended September 30, 2014 and 2013 was $392,000 and $102,000, respectively and $1.0 million and $209,000 for the nine month periods ended September 30, 2014 and 2013, respectively. As of September 30, 2014, there was $3.0 million of total unrecognized compensation expense related to unvested PSUs to be amortized through 2016.

A summary of the status and activity of PSUs for the nine months ended September 30, 2014 is presented below:

		Weighted-Average
		Grant-Date
	PSU	Fair Value
Non-vested at beginning of year (1)	40,191	$	32.05
Granted(1)	63,766	$	42.50
Vested(1)	—	$	—
Forfeited(1)	—	$	—
Non-vested at end of quarter(1)	103,957	$	38.46

(1) The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition.

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DERIVATIVES

9 Months Ended

Sep. 30, 2014

DERIVATIVES

DERIVATIVES

NOTE 10 - DERIVATIVES

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

As of September 30, 2014, and as of the filing date of this report, the Company had the following derivative commodity contracts in place:

		Total Volumes			Average		Average		Average		Fair Market
Settlement	Derivative	(Bbls/MMBtu	Average Fixed		Short Floor		Floor		Ceiling		Value of Asset
Period	Instrument	per day)	Price		Price		Price		Price		(Liability)
											(in thousands)
Oil
4Q 2014	Swap	6,370	$	95.62								3,166
1Q 2015	Swap	6,000	$	95.39								3,481
2Q 2015	Swap	5,000	$	94.21								2,940
3Q 2015	Swap	2,000	$	93.43								1,131
4Q 2015	Swap	2,000	$	93.43								1,177
4Q 2014	Collar	4,326					$	86.16	$	96.57		280
4Q 2014	3-Way Collar	2,000			$	65.00	$	87.68	$	99.75		249
1Q 2015	3-Way Collar	6,500			$	68.08	$	84.32	$	95.90		302
2Q 2015	3-Way Collar	5,500			$	67.73	$	84.09	$	95.16		321
3Q 2015	3-Way Collar	6,500			$	68.46	$	84.62	$	95.49		655
4Q 2015	3-Way Collar	6,500			$	68.46	$	84.62	$	95.49		660
1Q 2016	3-Way Collar	5,500			$	70.00	$	85.00	$	96.83		853
2Q 2016	3-Way Collar	5,500			$	70.00	$	85.00	$	96.83		856
3Q 2016	3-Way Collar	5,500			$	70.00	$	85.00	$	96.83		875
4Q 2016	3-Way Collar	5,500			$	70.00	$	85.00	$	96.83		789
											$	17,735
Gas
4Q 2014	3-Way Collar	30,000			$	3.63	$	4.21	$	4.81	$	496
1Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	(48)
2Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	190
3Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	137
4Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75	$	14
											$	789
Total											$	18,524

Derivative Assets and Liabilities Fair Value

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

The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of September 30, 2014 and December 31, 2013:

	As of September 30, 2014
	Balance Sheet Location	Fair Value
		(in thousands)
Derivative Assets:
Commodity contracts	Current assets	$	13,300
Commodity contracts	Noncurrent assets		5,224
Derivative Liabilities:
Commodity contracts	Current liabilities		—
Commodity contracts	Long-term liabilities		—
Total net derivative asset		$	18,524

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

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

	Three months ended  September 30,					Nine months ended September 30,
	2014		2013			2014		2013
	(in thousands)					(in thousands)
Derivative cash settlement gain (loss):
Oil contracts	$	(1,577)		$	(6,962)	$	(9,171)	$	(10,206)
Gas contracts		583			88		35		339
Total derivative cash settlement (loss)(1)	$	(994)		$	(6,874)	$	(9,136)	$	(9,867)
Change in fair value gain (loss)	$	51,840		$	(10,016)	$	23,897	$	(4,576)
Total derivative gain (loss)(2)	$	50,846		$	(16,890)	$	14,761	$	(14,443)

(1) Derivative cash settlement gain (loss) for the nine monthsended September 30, 2014 and 2013 is reported in the derivative cash settlements line item on the accompanying condensed consolidated statements of cash flows (the “statements of cash flows”) within the net cash used in investing activities.

(2) Total derivative gain (loss) for the nine months ended September 30, 2014 and 2013 is reported in the derivative gain (loss) line item on the accompanying statements of cash flows within the net cash provided by operating activities.

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FAIR VALUE MEASUREMENTS (Details 3) (USD $)	Sep. 30, 2014	Jul. 15, 2014	Dec. 31, 2013
Derivatives measured at fair value
Proved properties	$ 1,753,604,000		$ 1,257,288,000
Unproved properties	213,251,000		45,081,000
Asset retirement obligations	15,382,000		11,050,000
6.75% Senior Notes
Derivatives measured at fair value
Outstanding amount	500,000,000
Long-term debt	507,900,000		508,800,000
Interest rate (as a percent)	6.75%		6.75%
5.75% Senior Notes
Derivatives measured at fair value
Outstanding amount	300,000,000
Interest rate (as a percent)	5.75%	5.75%	5.75%
Fair value of Senior Notes	294,000,000
Fair Value
Derivatives measured at fair value
Proved properties	0		0
Unproved properties	0		0
Asset retirement obligations	0		0
Fair value of Senior Notes	$ 515,000,000		$ 527,500,000

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DISCONTINUED OPERATIONS (Tables)

9 Months Ended

Sep. 30, 2014

DISCONTINUED OPERATIONS

Schedule of the carrying amounts of the remaining properties included within assets held for sale classified as discontinued operations

	As of September 30,		As of December 31,
	2014		2013
	(in thousands)
Oil and gas properties, successful efforts method:
Proved properties	$	—	$	1,721
Unproved properties		—		1
Wells in progress		—		101
Total property and equipment		—		1,823
Less accumulated depreciation, depletion and amortization		—		(1,463)
Property and equipment, net	$	—	$	360

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands)
Net revenues:
Oil and gas sales	$	—	$	403	$	361	$	1,278
Operating expenses:
Lease operating		—		574		366		1,479
Severance and ad valorem taxes		—		—		12		1
Exploration		—		1		—		66
Depreciation, depletion and amortization		—		62		68		267
Total operating expenses				637		446		1,813
Loss from operations associated with oil and gas properties held for sale	$	—	$	(234)	$	(85)	$	(535)

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EARNINGS PER SHARE (Tables)

9 Months Ended

Sep. 30, 2014

EARNINGS PER SHARE

Schedule of calculation of earnings per basic and diluted shares from continuing and discontinued operations

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands, except per share amounts)
Income from continuing operations:
Income from continuing operations	$	48,854	$	17,925	$	59,696	$	44,081
Less: undistributed earnings to unvested restricted stock		914		446		1,124		1,055
Undistributed earnings to common shareholders		47,940		17,479		58,572		43,026
Basic income per common share from continuing operations	$	1.18	$	0.44	$	1.47	$	1.09
Diluted income per common share from continuing operations	$	1.18	$	0.44	$	1.46	$	1.09
Income (loss) from discontinued operations:
Income (loss) from discontinued operations	$	(72)	$	(144)	$	3,775	$	(329)
Less: undistributed earnings to unvested restricted stock		(1)		(4)		71		(8)
Undistributed earnings (loss) to common shareholders		(71)		(140)		3,704		(321)
Basic income per common share from discontinued operations	$	0.00	$	0.00	$	0.09	$	0.00
Diluted income per common share from discontinued operations	$	0.00	$	0.00	$	0.09	$	0.00
Net income:
Net income	$	48,782	$	17,781	$	63,471	$	43,752
Less: undistributed earnings to unvested restricted stock		913		442		1,195		1,047
Undistributed earnings to common shareholders		47,869		17,339		62,276		42,705
Basic net income per common share	$	1.18	$	0.44	$	1.56	$	1.09
Diluted net income per common share	$	1.18	$	0.44	$	1.55	$	1.09
Weighted-average shares outstanding - basic		40,556		39,356		39,958		39,315
Add: dilutive effect of contingent PSUs		152		19		147		34
Weighted-average shares outstanding - diluted		40,708		39,375		40,105		39,349

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CONSOLIDATED STATEMENTS OF OPERATIONS (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
CONSOLIDATED STATEMENTS OF OPERATIONS
General and administrative, stock compensation	$ 3,162	$ 2,652	$ 17,312	$ 9,716

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DISCONTINUED OPERATIONS

9 Months Ended

Sep. 30, 2014

DISCONTINUED OPERATIONS

DISCONTINUED OPERATIONS

NOTE 4 - DISCONTINUED OPERATIONS

During June 2012, the Company began marketing, with intent to sell, all of its oil and gas properties in California classifying them as assets held for sale. Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. The Company determined that its intent to sell all of its assets in a region qualified as discontinued operations. The Company sold its remaining property in this region during the first quarter of 2014 for approximately $6.0 million and recorded a gain on the sale of oil and gas properties in the amount of $6.2 million. The carrying amounts of the remaining properties included within assets held for sale classified as discontinued operations are presented below.

	As of September 30,		As of December 31,
	2014		2013
	(in thousands)
Oil and gas properties, successful efforts method:
Proved properties	$	—	$	1,721
Unproved properties		—		1
Wells in progress		—		101
Total property and equipment		—		1,823
Less accumulated depreciation, depletion and amortization		—		(1,463)
Property and equipment, net	$	—	$	360

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(in thousands)
Net revenues:
Oil and gas sales	$	—	$	403	$	361	$	1,278
Operating expenses:
Lease operating		—		574		366		1,479
Severance and ad valorem taxes		—		—		12		1
Exploration		—		1		—		66
Depreciation, depletion and amortization		—		62		68		267
Total operating expenses				637		446		1,813
Loss from operations associated with oil and gas properties held for sale	$	—	$	(234)	$	(85)	$	(535)

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ACQUISITIONS (Details) (Wattenberg Field Acquisition [Member], USD $)	0 Months Ended
	Jul. 08, 2014 acre
Wattenberg Field Acquisition [Member]
ACQUISITIONS
Purchase price	$ 223,650
Allocation of purchase price:
Proved properties	25,014
Unproved properties	198,729
Asset retirement obligation	(93)
Business Combination, Consideration Transferred, Total	$ 223,650
Gross area of acquired properties (in acres)	86,000
Net area of acquired properties (in acres)	34,000
Issuance of shares of common stock to acquiree	853,492
Per share value of shares of common stock sold to acquiree (in dollars per share)	$ 57.47

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EARNINGS PER SHARE (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Income from continuing operations:
Income from continuing operations	$ 48,854	$ 17,925	$ 59,696	$ 44,081
Less: undistributed earnings to unvested restricted stock	914	446	1,124	1,055
Undistributed earnings to common shareholders	47,940	17,479	58,572	43,026
Basic income per common share from continuing operations (in dollars per share)	$ 1.18	$ 0.44	$ 1.47	$ 1.09
Diluted income per common share from continuing operations (in dollars per share)	$ 1.18	$ 0.44	$ 1.46	$ 1.09
Income (loss) from discontinued operations:
Income (loss) from discontinued operations	(72)	(144)	3,775	(329)
Less: undistributed earnings to unvested restricted stock	(1)	(4)	71	(8)
Undistributed earnings (loss) to common shareholders	(71)	(140)	3,704	(321)
Basic loss per common share from discontinued operations (in dollars per share)	$ 0.00	$ 0.00	$ 0.09	$ 0.00
Diluted loss per common share from discontinued operations (in dollars per share)	$ 0.00	$ 0.00	$ 0.09	$ 0.00
Net income:
Net Income	48,782	17,781	63,471	43,752
Less: undistributed earnings to unvested restricted stock	913	442	1,195	1,047
Undistributed earnings to common shareholders	$ 47,869	$ 17,339	$ 62,276	$ 42,705
Basic net income per common share (in dollars per share)	$ 1.18	$ 0.44	$ 1.56	$ 1.09
Diluted net income per common share (in dollars per share)	$ 1.18	$ 0.44	$ 1.55	$ 1.09
Weighted-average shares outstanding - basic	40,556	39,356	39,958	39,315
Add: dilutive effect of contingent PSUs	152	19	147	34
Weighted-average shares outstanding - diluted	40,708	39,375	40,105	39,349
Antidilutive shares	0	0
PSUs | Minimum
EARNINGS PER SHARE
Percentage of awards earned during performance cycle			0
PSUs | Maximum
EARNINGS PER SHARE
Percentage of awards earned during performance cycle			200

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ACQUISITIONS (Tables)

9 Months Ended

Sep. 30, 2014

ACQUISITIONS

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

		Asset Valuation Amount
		(in thousands)
Purchase price	$	223,650
Allocation of purchase price:
Proved properties	$	25,014
Unproved properties		198,729
Asset retirement obligation		(93)
Total	$	223,650