Edgar Filing: Bonanza Creek Energy, Inc.

bcei_Current folio_10Q

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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 March 31, 2015

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 May 4, 2015, the registrant had 49,701,874 shares of common stock outstanding.

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BONANZA CREEK ENERGY, INC.

INDEX


			PAGE
Part I.	FINANCIAL INFORMATION

	Item 1.	Financial Statements (Unaudited)

		Condensed Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014	3

		Condensed Consolidated Statements of Operations and Comprehensive Income for the Three Months Ended March 31, 2015 and 2014	4

		Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014	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	25

	Item 4.	Controls and Procedures	26

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	27

	Item 3.	Defaults Upon Senior Securities	27

	Item 4.	Mine Safety Disclosures	28

	Item 5.	Other Information	28

	Item 6.	Exhibits	29

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PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)


	As of
	March 31, 2015		December 31, 2014
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	70,514	$	2,584
Accounts receivable:
Oil and gas sales		39,273		54,574
Joint interest and other		36,205		37,202
Prepaid expenses and other		14,395		12,522
Inventory of oilfield equipment		18,312		15,353
Derivative asset		69,056		86,240
Total current assets		247,755		208,475
Property and equipment (successful efforts method), at cost:
Proved properties		2,072,397		1,924,380
Less: accumulated depreciation, depletion and amortization		(649,015)		(592,073)
Total proved properties, net		1,423,382		1,332,307
Unproved properties		202,409		206,721
Wells in progress		111,964		139,208
Natural gas plant, net of accumulated depreciation of $9,097 in 2015 and $8,457 in 2014		67,313		67,840
Other property and equipment, net of accumulated depreciation of $7,052 in 2015 and $6,087 in 2014		10,932		10,401
Total property and equipment, net		1,816,000		1,756,477
Long-term derivative asset		18,339		17,765
Other noncurrent assets		32,656		23,372
Total assets	$	2,114,750	$	2,006,089
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses (note 4)	$	119,004	$	145,788
Oil and gas revenue distribution payable		30,215		40,659
Contractual obligation for land acquisition		12,000		12,000
Total current liabilities		161,219		198,447
Long-term liabilities:
Long-term debt (note 5)		807,313		840,619
Contractual obligation for land acquisition		11,535		11,186
Ad valorem taxes		33,002		28,635
Deferred income taxes		154,129		165,667
Asset retirement obligations		21,786		21,464
Total liabilities		1,188,984		1,266,018
Commitments and contingencies (note 6)
Stockholders’ equity:
Preferred stock, $.001 par value, 25,000,000 shares authorized, none outstanding		—		—
Common stock, $.001 par value, 225,000,000 shares authorized, 49,617,775 and 41,287,270 issued and outstanding in 2015 and 2014, respectively		50		41
Additional paid-in capital		795,618		591,511
Retained earnings		130,098		148,519
Total stockholders’ equity		925,766		740,071
Total liabilities and stockholders’ equity	$	2,114,750	$	2,006,089

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

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (UNAUDITED)


	Three Months Ended March 31,
	2015		2014
	(in thousands, except per share amounts)
Operating net revenues:
Oil and gas sales	$	73,076	$	127,395
Operating expenses:
Lease operating expense		19,264		17,082
Severance and ad valorem taxes		6,496		10,749
Exploration		498		1,083
Depreciation, depletion and amortization		59,004		41,132
Abandonment and impairment of unproved properties		5,469		—
General and administrative (including $3,427 and $6,797 in 2015 and 2014, respectively, of stock compensation)		16,872		23,714
Total operating expenses		107,603		93,760
Income (loss) from operations		(34,527)		33,635
Other income (expense):
Derivative gain (loss)		18,856		(8,778)
Interest expense		(14,238)		(9,335)
Other income (loss)		(49)		51
Total other income (expense)		4,569		(18,062)
Income (loss) from continuing operations before taxes		(29,958)		15,573
Income tax benefit (expense)		11,537		(5,996)
Income (loss) from continuing operations	$	(18,421)	$	9,577
Discontinued operations (note 3):
Loss from operations associated with oil and gas properties held for sale		—		(85)
Gain on sale of oil and gas properties		—		6,514
Income tax expense		—		(2,475)
Gain from discontinued operations		—		3,954
Net income (loss)	$	(18,421)	$	13,531
Comprehensive income (loss)	$	(18,421)	$	13,531
Basic and diluted income (loss) per share:
Income (loss) from continuing operations	$	(0.41)	$	0.24
Income from discontinued operations	$	—	$	0.10
Net income (loss) per common share	$	(0.41)	$	0.34
Basic weighted-average common shares outstanding		44,519,701		39,605,083
Diluted weighted-average common shares outstanding		44,519,701		39,761,738

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

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Three Months Ended March 31,
	2015		2014
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$	(18,421)	$	13,531
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		59,004		41,199
Deferred income taxes		(11,537)		8,471
Abandonment and impairment of unproved properties		5,469		—
Stock-based compensation		3,427		6,797
Amortization of deferred financing costs and debt premium		523		255
Accretion of contractual obligation for land acquisition		349		190
Derivative (gain) loss		(18,856)		8,778
Gain on sale of oil and gas properties		—		(6,514)
Other		(27)		(2)
Changes in current assets and liabilities:
Accounts receivable		16,298		(12,721)
Prepaid expenses and other assets		(1,873)		(2,637)
Accounts payable and accrued liabilities		(1,981)		20,337
Settlement of asset retirement obligations		(285)		—
Net cash provided by operating activities		32,090		77,684
Cash flows from investing activities:
Acquisition of oil and gas properties		(11,382)		(1,202)
Proceeds from sale of oil and gas properties		—		6,000
Exploration and development of oil and gas properties		(154,300)		(123,835)
Natural gas plant capital expenditures		(112)		(194)
Derivative cash settlements		35,466		(2,227)
Additions to property and equipment - non oil and gas		(1,490)		(838)
Net cash used in investing activities		(131,818)		(122,296)
Cash flows from financing activities:
Proceeds from credit facility		44,000		—
Payments to credit facility		(77,000)		—
Proceeds from sale of common stock		209,300		—
Offering costs related to sale of common stock		(6,492)		—
Offering costs related to sale of Senior Notes		(19)		(140)
Payment of employee tax withholdings in exchange for the return of common stock		(2,127)		(4,461)
Deferred financing costs		(4)		(26)
Net cash provided by (used in) financing activities		167,658		(4,627)
Net change in cash and cash equivalents		67,930		(49,239)
Cash and cash equivalents:
Beginning of period		2,584		180,582
End of period	$	70,514	$	131,343
Supplemental cash flow disclosure:
Cash paid for interest	$	9,894	$	464
Cash paid for income taxes	$	820	$	—
Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition	$	(30,880)	$	23,238

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

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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, which the Company has designated the Rocky Mountain region and the Dorcheat Macedonia Field in southern Arkansas, which the Company has designated the 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, 2014 (the “2014 Form 10-K”), except as disclosed herein. These consolidated financial statements include all of the adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and results of operations. All such adjustments are of a normal recurring nature only. The results of operations for the quarterly periods are not necessarily indicative of the results to be expected for the full fiscal year. The Company evaluated events subsequent to the balance sheet date of March 31, 2015 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, Bonanza Creek Energy Upstream LLC, Bonanza Creek Energy Midstream, LLC, Holmes Eastern Company, LLC and Rocky Mountain Infrastructure, 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 2014 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 2014 Form 10-K.

Recently Issued Accounting Standards

In March 2015, the Financial Accounting Standards Board issued Update No. 2015-03 – Interest – Imputation of Interest, Simplifying the Presentation of Debt Issuance Costs. The update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. This authoritative accounting guidance is effective for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years on a retrospective basis. 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.

NOTE 3 - 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

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Company sold its remaining property in this region during the first quarter of 2014 for approximately $6.0 million and recorded a gain on sale of oil and gas properties in the amount of $6.5 million as of March 31, 2014.

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


	Three Months Ended March 31,
	2015		2014
	(in thousands)
Net revenues:
Oil and gas sales	$	—	$	361
Operating expenses:
Lease operating expense		—		366
Severance and ad valorem taxes		—		13
Depreciation, depletion and amortization		—		67
Total operating expenses				446
Loss from operations associated with oil and gas properties held for sale	$	—	$	(85)

NOTE 4 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses contain the following:


	As of March 31,		As of December 31,
	2015		2014
	(in thousands)
Drilling and completion costs	$	51,964	$	82,844
Accounts payable trade		15,326		5,493
Accrued general and administrative cost		6,755		13,541
Lease operating expense		4,249		3,569
Accrued reclamation cost		162		162
Accrued interest		18,311		14,839
Production and ad valorem taxes and other		22,237		25,340
Total accounts payable and accrued expenses	$	119,004	$	145,788

NOTE 5 - LONG-TERM DEBT

Long-term debt consisted of the following as of March 31, 2015 and December 31, 2014:


	As of March 31,		As of December 31,
	2015		2014
		(in thousands)
Revolving credit facility	$	—	$	33,000
6.75% Senior Notes due 2021		500,000		500,000
Unamortized premium on 6.75% Senior Notes		7,313		7,619
5.75% Senior Notes due 2023		300,000		300,000
Total long-term debt	$	807,313	$	840,619

Credit Facility

The Company’s senior secured revolving Credit Agreement (the “revolving credit facility”), dated March 29, 2011, as amended, provides for borrowings up to $1 billion. As of March 31, 2015, the borrowing base under the revolving credit facility was $600 million. The Company elected to limit bank commitments at $500 million while reserving the option to access, at the Company’s request, the full $600 million borrowing base. The borrowing base is redetermined semiannually on May 15 and November 15. The revolving credit facility is collateralized by substantially all of the Company’s assets and matures on September 15, 2018. As of March 31, 2015, the Company had no outstanding balance under the revolving credit facility with an available borrowing capacity of $576 million, if the Company elected to take advantage of the entire borrowing base (without giving effect to any scheduled or interim redetermination), after reduction for the outstanding letter of credit of $24 million. As of December 31, 2014, the Company had $33 million outstanding under the revolving credit facility with an

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available borrowing capacity of $543 million, if the Company elected to take advantage of the entire borrowing base, after reduction for the outstanding letter of credit of $24 million.

The revolving credit facility restricts, among other items, the payment of dividends, certain additional indebtedness, sale of assets, loans and certain investments and mergers. The revolving credit facility also contains certain financial covenants, which require the maintenance of minimum current and debt coverage ratios, as defined by the revolving credit facility. The Company was in compliance with all financial and non-financial covenants as of March 31, 2015, and through the filing date of this report.

Senior Notes

The $500 million aggregate principal amount of 6.75% Senior Notes that mature on April 15, 2021 (“6.75% Senior Notes”) and the $300 million aggregate principal amount of 5.75% Senior Notes that mature on February 1, 2023 (“5.75% Senior Notes” and together with the 6.75% Senior Notes, the “Senior Notes”) are unsecured senior obligations and rank equal in right of payment with all of the Company’s existing and any future unsecured senior debt, and are senior in right of payment to any future subordinated debt. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by our existing and future domestic subsidiaries that guarantee or are borrowers under our revolving credit facility. 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. The Company is subject to certain covenants under the respective indentures governing the Senior Notes that limit the Company’s ability to incur additional indebtedness, issue preferred stock, and make restricted payments, including dividends. The Company was in compliance with all covenants under its Senior Notes as of March 31, 2015, and through the filing date of this report.

NOTE 6 - 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 condensed 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 filing date of this report, there were no material pending or overtly threatened legal actions against the Company of which it is aware.

Commitments

There have been no material changes from the commitments disclosed in the notes to the Company’s consolidated financial statements included in the 2014 Form 10-K.

NOTE 7 - STOCK-BASED COMPENSATION

Restricted Stock under the Long Term Incentive Plan

The Company grants shares of restricted stock to directors, eligible employees and officers under its Long Term Incentive Plan (“LTIP”). Each share of restricted stock represents one share of the Company’s common stock to be released from restriction upon completion of the vesting period. The awards typically vest in one-third increments over three years. Each share of restricted stock is entitled to a non‑forfeitable dividend, if the Company

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were to declare one, and has the same voting rights as a share of the Company’s common stock. 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 three months ended March 31, 2015, the Company granted 355,598 shares of restricted stock under the Company’s LTIP to certain employees. The fair value of the issuance was $9.6 million. Total expense recorded for restricted stock for the three month periods ended March 31, 2015 and 2014, was $2.9 million and $6.6 million, respectively. As of March 31, 2015, unrecognized compensation cost was $24.3 million and will be amortized through 2018.

A summary of the status and activity of non-vested restricted stock for the three months ended March 31, 2015 is presented below.


		Weighted-
		Average
	Restricted	Grant-Date
	Stock	Fair Value
Non-vested at beginning of year	589,529	$	37.66
Granted	355,598	$	27.11
Vested	(208,113)	$	26.21
Forfeited	(3,291)	$	43.97
Non-vested at end of quarter	733,723	$	34.53

Performance Stock Units under the Long Term Incentive Plan

The Company grants performance stock units (“PSUs”) to certain officers as part of its LTIP. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. 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 in 2014 and thereafter 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 of the Company’s common stock 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. The performance criterion for the PSUs is based on a comparison of the Company’s total shareholder return (“TSR”) for the measurement period compared with the TSRs of a group of peer companies for the measurement period. Compensation expense associated with PSUs is recognized as general and administrative expense over the measurement period.

The fair value of each PSU is estimated at the date of grant using a Monte Carlo simulation, which results in an expected percentage of PSUs to be earned during the performance period. The following table presents the assumptions used to determine the fair value of the PSUs granted during the three months ended March 31, 2015 and for the year ended December 31, 2014.


	For the Three Months Ended	For the Year Ended
	March 31, 2015	December 31, 2014
Expected term of award	3	3
Risk-free interest rate	0.17% - 0.99%	0.12% - 0.9%
Expected volatility	65%	40% - 45%

During the three months ended March 31, 2015, the Company granted 42,217 PSUs under the LTIP to certain officers. The fair value of the issuance was $1.5 million. Total expense recorded for PSUs for the three month periods ended March 31, 2015 and 2014 was $488,000 and $174,000, respectively. As of March 31, 2015, there was $4.5 million of total unrecognized compensation expense related to unvested PSUs to be amortized through 2018.

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A summary of the status and activity of PSUs for the three months ended March 31, 2015 is presented below:


		Weighted-Average
		Grant-Date
	PSU	Fair Value
Non-vested at beginning of year(1)	94,173	$	37.55
Granted(1)	42,217	$	34.50
Vested(1)	—	$	—
Forfeited(1)	—	$	—
Non-vested at end of quarter(1)	136,390	$	36.61

(1)

The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of the Company’s 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 8 - FAIR VALUE MEASUREMENTS

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

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

Level 2:Quoted prices in active markets for similar assets and liabilities, 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 and non-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 and non-financial assets and liabilities that were accounted for at fair value as of March 31, 2015 and December 31, 2014 and their classification within the fair value hierarchy:


	As of March 31, 2015
	Level 1		Level 2		Level 3
	(in thousands)
Derivative assets(1)	$	—	$	87,395	$	—
Unproved properties(2)	$	—	$	—	$	193,400

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	As of December 31, 2014
	Level 1		Level 2		Level 3
	(in thousands)
Derivative assets(1)	$	—	$	104,005	$	—
Proved properties(2)	$	—	$	—	$	407,900
Asset retirement obligations(3)	$	—	$	—	$	6,200

(1)

This represents a financial asset or liability that is measured at fair value on a recurring basis.

(2)

This represents non-financial assets that are measured at fair value on a nonrecurring basis due to impairments. This is the fair value of the asset base that was subjected to impairment and does not reflect the entire asset balance as presented on the accompanying balance sheets. Please refer to the Unproved Oil and Gas Properties and Proved Oil and Gas Properties sections below for additional discussion.

(3)

This represents the revision to estimate of the asset retirement obligation, which is a non-financial liability that is measured at fair value on a nonrecurring basis. Please refer to the Asset Retirement Obligation section below for additional discussion.

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 revolving credit facility.

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 risk-adjusted discount rates and price forecasts selected by the Company’s management. The calculation of the risk-adjusted discount rate is a significant management estimate based on the best information available. Management believes that the risk-adjusted discount rate is representative of current market conditions and reflects the following factors: estimates of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on the NYMEX strip pricing, adjusted for basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. There were no proved properties measured at fair value at March 31, 2015. The Company impaired the Dorcheat Macedonia Field which had a carrying value of $519.2 million to its fair value of $391.9 million and recognized an impairment of $127.3 million for the year ended December 31, 2014. The Company impaired the McKamie Patton Field which had a carrying value of $41.0 million to its fair value of $16.0 million and recognized an impairment of $25.0 million for the year ended December 31, 2014. The Company impaired the McCallum Field which had a carrying value of $15.3 million to its fair value of zero and recognized an impairment of $15.3 for the year ended December 31, 2014.

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 fully 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, remaining lease life, and estimated reserve values. Unproved properties classified as held for sale are valued using a market approach,

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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. The Company impaired the Wattenberg Field which had a carrying value of $198.9 million to its fair value of $193.4 million and recognized an impairment of unproved properties of $5.5 million due to lease expirations for the three months ended March 31, 2015. There were no unproved properties measured at fair value as of December 31, 2014.

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 as of March 31, 2015. The Company had $6.2 million of asset retirement obligations recorded at fair value as of December 31, 2014.

Long-term Debt

As of March 31, 2015, the Company had $500 million of outstanding 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 $507.3 million and $507.6 million as of March 31, 2015 and December 31, 2014, respectively. The fair value of the 6.75% Senior Notes as of March 31, 2015 and December 31, 2014 was $486.3 million and $440.0 million, respectively. The 5.75% Senior Notes are recorded at cost on the accompanying balance sheets at $300.0 million as of March 31, 2015 and December 31, 2014. The fair value of the 5.75% Senior Notes as of March 31, 2015 and December 31, 2014 was $277.1 million and $243.0 million, respectively. The Senior Notes are measured using Level 1 inputs based on a secondary market trading price. The Company’s revolving credit facility, when drawn upon, approximates fair value as the applicable interest rates are floating.

NOTE 9 - 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 March 31, 2015, and as of the filing date of this report, the Company had the following derivative commodity contracts in place:


		Total Volumes			Average		Average		Average
Settlement	Derivative	(Bbls/MMBtu	Average Fixed		Short Floor		Floor		Ceiling		Fair Market
Period	Instrument	per day)	Price		Price		Price		Price		Value of Assets
												(in thousands)
Oil
2Q 2015	Swap	5,000	$	94.41								$	20,315
3Q 2015	Swap	2,000	$	93.43									7,428
4Q 2015	Swap	2,000	$	93.43									7,022
2Q 2015	3-Way Collar	5,500			$	67.73	$	84.09	$	95.16			8,097
3Q 2015	3-Way Collar	6,500			$	68.46	$	84.62	$	95.49			9,112
4Q 2015	3-Way Collar	6,500			$	68.46	$	84.62	$	95.49			8,619
2016	3-Way Collar	5,500			$	70.00	$	85.00	$	96.83			24,922
												$	85,515
Gas
2Q - 4Q 2015	3-Way Collar	15,000			$	3.50	$	4.00	$	4.75		$	1,880
												$	1,880

Total												$	87,395

Derivative Assets and Liabilities Fair Value

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

The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of March 31, 2015 and December 31, 2014:


	As of March 31, 2015
	Balance Sheet Location	Fair Value
		(in thousands)
Derivative Assets:
Commodity contracts	Current assets	$	69,056
Commodity contracts	Noncurrent assets		18,339
Derivative Liabilities:
Commodity contracts	Current liabilities		—
Commodity contracts	Long-term liabilities		—
Total derivative asset		$	87,395


	As of December 31, 2014
	Balance Sheet Location	Fair Value
		(in thousands)
Derivative Assets:
Commodity contracts	Current assets	$	86,240
Commodity contracts	Noncurrent assets		17,765
Derivative Liabilities:
Commodity contracts	Current liabilities		—
Commodity contracts	Long-term liabilities		—
Total derivative asset		$	104,005

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


	Three months ended March 31,
	2015		2014
	(in thousands)
Derivative cash settlement gain (loss):
Oil contracts	$	34,791	$	(1,699)
Gas contracts		675		(528)
Total derivative cash settlement gain (loss)(1)	$	35,466	$	(2,227)

Change in fair value loss	$	(16,610)	$	(6,551)

Total derivative gain (loss)(2)	$	18,856	$	(8,778)

(1)

Derivative cash settlement gain (loss) for the three months ended March 31, 2015 and 2014 is reported in the derivative cash settlements line item on the accompanying condensed consolidated statements of cash flows within the net cash for investing activities.

(2)

Total derivative gain (loss) for the three months ended March 31, 2015 and 2014 is reported in the derivative gain (loss) line item on the accompanying condensed consolidated statements of cash flows within the net cash provided by operating activities.

NOTE 10 - 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 measurement period applicable to such PSUs. Please refer to Note 7 - 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 and net income (loss) for the three month periods ended March 31, 2015 and 2014:


	Three Months Ended March 31,
	2015		2014
	(in thousands, except per share amounts)
Income (loss) from continuing operations:
Income (loss) from continuing operations	$	(18,421)	$	9,577
Less: undistributed earnings (loss) to unvested restricted stock		(314)		181
Undistributed earnings (loss) to common shareholders		(18,107)		9,396
Basic income (loss) per common share from continuing operations	$	(0.41)	$	0.24
Diluted income (loss) per common share from continuing operations	$	(0.41)	$	0.24

Income from discontinued operations:
Income from discontinued operations	$	—	$	3,954
Less: undistributed earnings to unvested restricted stock		—		75
Undistributed earnings to common shareholders		—		3,879
Basic income per common share from discontinued operations	$	—	$	0.10
Diluted income per common share from discontinued operations	$	—	$	0.10

Net income (loss):
Net income (loss)	$	(18,421)	$	13,531
Less: undistributed earnings (loss) to unvested restricted stock		(314)		256
Undistributed earnings (loss) to common shareholders		(18,107)		13,275
Basic net income (loss) per common share	$	(0.41)	$	0.34
Diluted net income (loss) per common share	$	(0.41)	$	0.34

Weighted-average shares outstanding - basic		44,519,701		39,605,083
Add: dilutive effect of contingent PSUs		—		156,655
Weighted-average shares outstanding - diluted		44,519,701		39,761,738

The Company was in a net loss position for the three months ended March 31, 2015, which made the 147,786 potentially dilutive shares anti-dilutive. The Company had no anti-dilutive shares for the three months ended March 31, 2014.

NOTE 11 - CAPITAL STOCK

On February 6, 2015, the Company completed a public offering of 8,050,000 shares of its common stock generating net proceeds of $202.8 million after deducting underwriter discounts, commissions and offering expenses of approximately $6.5 million. The Company used a portion of the net proceeds to repay all of the outstanding borrowings under its revolving credit facility and intends to use the remaining net proceeds for general corporate purposes, including its drilling and development program and other capital expenditures.

NOTE 12 - INCOME TAXES

The Company uses the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time. During the three month periods ended March 31, 2015 and 2014, the effective tax rate was 38.5%.

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.

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As of March 31, 2015, the Company had no unrecognized tax benefits. The Company’s management does not believe that there are any new items or changes in facts or judgments that should impact the Company's tax position during the first quarter of 2015. Given the substantial net operating loss carry forward at the federal level, neither significant interest expense nor penalties charged for any examining agents’ tax adjustments of income tax returns are anticipated, as any such adjustments would very likely adjust only net operating loss carry forward.

NOTE 13 – SUBSEQUENT EVENTS

During the first quarter of 2015, the Company formed a wholly owned subsidiary, Rocky Mountain Infrastructure, LLC, to hold gathering systems and related infrastructure that service the Wattenberg Field. Subsequent to March 31, 2015, the Company transferred approximately $38 million of gathering systems and pipelines from the Bonanza Creek Energy Operating Company, LLC subsidiary to the Rocky Mountain Infrastructure, LLC subsidiary.

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, 2014, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

Executive Summary

We are 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, which we have designated the Rocky Mountain region, and the Dorcheat Macedonia Field in southern Arkansas, which we have designated the Mid-Continent region. The Wattenberg Field is one of the premier oil and gas resource plays in the United States benefiting from a low cost structure and strong production efficiencies. Our management team has extensive experience acquiring and operating oil and gas properties and significant expertise in horizontal drilling and fracture stimulation, which we believe will continue to contribute to the development of our sizable inventory of projects, including those targeting the Niobrara and Codell formations in the Rocky Mountain region and oily Cotton Valley sands in the Mid-Continent region. Our corporate strategy is to create shareholder value by increasing sales volumes from our Wattenberg horizontal opportunities and develop additional resource potential in both of our core areas while capitalizing on well cost reduction gained through efficiencies, managing risk exposure through derivative contracts, and engaging in prudent evaluation of potential acquisitions. We operate approximately 98% of our proved reserves with an average working interest of approximately 86% providing us with significant control over the rate of development of our asset base. Despite the uncertainty surrounding the global economy and volatility in commodity prices, we believe the economic returns and economic growth generated by our portfolio of oil and gas assets position us well moving forward.

Effective as of January 1, 2015, the Company revised the agreements with its natural gas processors in the Rocky Mountain region to report operated sales volumes on a three stream basis, which allows for separate reporting of NGLs extracted from the natural gas stream and sold as a separate product. The contract revisions necessitated a change in our reporting of sales volumes. Prior period sales volumes, revenues, and prices have not been reclassified to conform to the current presentation given the prospective nature of the agreements. The NGL volumes identified by the Company’s gas purchasers are converted to an oil equivalent. The Company believes that this conversion will more accurately convey its production and sales volumes and will allow results to be more comparable with those of our peers. This revision will increase sales volumes and the percentage of sales volumes that relate to NGLs.

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Financial and Operating Highlights

Our financial results and operational highlights for the first quarter of 2015 included:

Total liquidity of $646.5 million, consisting of a period-end cash balance plus funds available under our revolving credit facility, as compared with $545.3 million for the first quarter of 2014;

Completed a public offering of 8,050,000 shares of our common stock on February 6, 2015, which generated net proceeds of $202.8 million;

Increased sales volumes by 40% to 2,475.8 MBoe in the first quarter of 2015 from 1,773.1 MBoe in the first quarter of 2014, with oil and NGL production representing 76% of total sales volumes in the first quarter of 2015;

Cash operating costs, which consist of lease operating expense, severance and ad valorem taxes, and the cash portion of general and administrative expense, per barrel decreased by $9.40 per Boe to $15.83 per Boe as compared to the first quarter of 2014;

Projected drilling and completion AFEs on 4,000 foot laterals have decreased by 20% from $4.5 million to $3.6 million during the first quarter of 2015 from 2014 drilling and completion AFEs;

The Company established a midstream subsidiary, Rocky Mountain Infrastructure, LLC to house our gathering systems and related infrastructure that service the Wattenberg Field and revised our natural gas processing agreements to allow for three stream reporting;

Experienced average cumulative production of 40,000 Boe per well for the first 120 days of production on 9 wells in the Wattenberg Field using a 28-stage fracture design;

Drilled 30 and completed 32 gross wells within our Rocky Mountain region and drilled 9 and completed 5 gross wells within our Mid-Continent region during the first quarter of 2015;

Capital expenditures of $123.4 million, as compared with $151.9 million for the first quarter of 2014; and

Cash flows provided by operating activities of $32.1 million, as compared with $77.7 million for the first quarter of 2014.

Outlook for 2015

Because the global economic outlook, central bank policies and commodity price environment are uncertain, we have planned a flexible capital spending program for 2015. We estimate our total capital expenditures in 2015 to be approximately $420 million, allocating approximately 90% to the Wattenberg Field and 10% to southern Arkansas. Actual capital expenditures are subject to a number of factors, including economic conditions and commodity prices, and the Company may reduce or augment the capital budget as appropriate throughout the year. This estimated capital investment is expected to result in sales volumes of 27,800 Boe/d to 30,700 Boe/d, while maintaining a strong oil and liquids profile.

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Results of Continuing Operations

Three Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014

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


	Three Months Ended March 31,
							Percent
	2015		2014		Change		Change
	(In thousands, except percentages)
Revenues:
Crude oil sales	$	59,420	$	103,747	$	(44,327)	(43)	%
Natural gas sales		7,988		18,515		(10,527)	(57)	%
Natural gas liquids sales		5,668		5,126		542	11	%
CO2 sales		—		7		(7)	(100)	%
Product revenue	$	73,076	$	127,395	$	(54,319)	(43)	%

Sales Volumes:
Crude oil (MBbls)		1,490.5		1,164.2		326.3	28	%
Natural gas (MMcf)		3,506.9		3,089.2		417.7	14	%
Natural gas liquids (MBbls)		400.8		94.0		306.8	326	%
Crude oil equivalent (MBoe)(1)		2,475.8		1,773.1		702.7	40	%

Average Sales Prices (before derivatives)(2):
Crude oil (per Bbl)	$	39.87	$	89.11	$	(49.24)	(55)	%
Natural gas (per Mcf)	$	2.28	$	5.99	$	(3.71)	(62)	%
Natural gas liquids (per Bbl)	$	14.14	$	54.53	$	(40.39)	(74)	%
Crude oil equivalent (per Boe)(1)	$	29.52	$	71.85	$	(42.33)	(59)	%

Average Sales Prices (after derivatives)(2):
Crude oil (per Bbl)	$	63.21	$	87.65	$	(24.44)	(28)	%
Natural gas (per Mcf)	$	2.47	$	5.82	$	(3.35)	(58)	%
Natural gas liquids (per Bbl)	$	14.14	$	54.53	$	(40.39)	(74)	%
Crude oil equivalent (per Boe)(1)	$	43.84	$	70.59	$	(26.75)	(38)	%

(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 decreased by 43%, to $73.1 million for the three months ended March 31, 2015 compared to $127.4 million for the three months ended March 31, 2014 due to a 59% decrease in oil equivalent pricing. The decreased pricing was offset by increased sales volumes of 40% for the three months ended March 31, 2015 compared to the same period in 2014. The increased volumes are a direct result of the $498.8 million expended for drilling and completion during the last three quarters of 2014 and $121.6 million expended during the three months ended March 31, 2015. During the period from March 31, 2014 through March 31, 2015, we drilled 128 and completed 106 gross wells in the Rocky Mountain region and drilled 42 and completed 46 gross wells in the Mid-Continent region.

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


	Three Months Ended March 31,
							Percent
	2015		2014		Change		Change
	(In thousands, except percentages)
Expenses:
Lease operating expense	$	19,264	$	17,082	$	2,182	13	%
Severance and ad valorem taxes		6,496		10,749		(4,253)	(40)	%
Exploration		498		1,083		(585)	(54)	%
Depreciation, depletion and amortization		59,004		41,132		17,872	43	%
Abandonment and impairment of unproved properties