CIVITAS RESOURCES, INC. - Quarter Report: 2016 March (Form 10-Q)

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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, 2016

Commission File Number: 001-35371

Bonanza Creek Energy, Inc.

(Exact name of registrant as specified in its charter)



Delaware		61-1630631
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)



410 17th Street, Suite 1400
Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

(720) 440-6100

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes ¨ 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 x		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 x 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 2, 2016, the registrant had 49,621,879 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, 2016 and December 31, 2015	3

		Condensed Consolidated Statements of Operations and Comprehensive Income for the Three Months Ended March 31, 2016 and 2015	4

		Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2016 and 2015	5

		Notes to the Condensed Consolidated Financial Statements	6

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	25

	Item 4.	Controls and Procedures	26

Part II.	OTHER INFORMATION

	Item 1.	Legal Proceedings	26

	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	27

	Item 5.	Other Information	27

	Item 6.	Exhibits	28

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PART I - FINANCIAL INFORMATION

Item 1. Financial Statements.

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)



	March 31, 2016			December 31, 2015
	(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	218,599		$	21,341
Accounts receivable:
Oil and gas sales	23,391			25,322
Joint interest and other	10,111			31,224
Prepaid expenses and other	5,700			4,078
Inventory of oilfield equipment	8,798			8,543
Derivative asset	21,052			29,566
Total current assets	287,651			120,074
Property and equipment (successful efforts method), at cost:
Proved properties	1,658,867			1,618,970
Less: accumulated depreciation, depletion and amortization	(967,941		)	(943,081		)
Total proved properties, net	690,926			675,889
Unproved properties	178,948			185,530
Wells in progress	27,058			51,196
Oil and gas properties and natural gas plant held for sale, net of accumulated depreciation, depletion and amortization of $646,917 and $636,917 in 2016 and 2015, respectively (note 3)	209,421			214,922
Other property and equipment, net of accumulated depreciation of $9,976 in 2016 and $9,407 in 2015	9,044			9,729
Total property and equipment, net	1,115,397			1,137,266
Other noncurrent assets	17,799			16,027
Total assets	$	1,420,847		$	1,273,367
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses (note 4)	$	78,992		$	96,360
Oil and gas revenue distribution payable	23,905			27,613
Contractual obligation for land acquisition	12,000			12,000
Total current liabilities	114,897			135,973
Long-term liabilities:
Long-term debt (note 5)	1,094,085			885,392
Ad valorem taxes	20,789			17,069
Asset retirement obligations	15,352			14,935
Asset retirement obligations for assets held for sale	10,779			10,591
Total liabilities	1,255,902			1,063,960

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, 49,635,517 and 49,754,408 issued and outstanding in 2016 and 2015, respectively	49			49
Additional paid-in capital	809,161			806,386
Retained deficit	(644,265		)	(597,028		)
Total stockholders’ equity	164,945			209,407
Total liabilities and stockholders’ equity	$	1,420,847		$	1,273,367

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,
	2016			2015
	(in thousands, except per share amounts)
Operating net revenues:
Oil and gas sales	$	44,174		$	73,076
Operating expenses:
Lease operating expense	13,298			16,973
Gas plant and midstream operating expense	3,789			2,291
Severance and ad valorem taxes	3,154			6,496
Exploration	266			498
Depreciation, depletion and amortization	26,379			59,004
Impairment of oil and gas properties	10,000			—
Abandonment and impairment of unproved properties	6,906			5,469
General and administrative (including $3,004 and $3,427, respectively, of stock-based compensation)	17,685			16,872
Total operating expenses	81,477			107,603
Loss from operations	(37,303		)	(34,527		)
Other income (expense):
Derivative gain (loss)	(1,007		)	18,856
Interest expense	(14,547		)	(14,238		)
Gain on termination fee (note 3)	6,000			—
Other loss	(380		)	(49		)
Total other income (expense)	(9,934		)	4,569
Loss from operations before taxes	(47,237		)	(29,958		)
Income tax benefit	—			11,537
Net loss	$	(47,237	)	$	(18,421	)
Comprehensive loss	$	(47,237	)	$	(18,421	)

Basic net loss per common share	$	(0.96	)	$	(0.41	)

Diluted net loss per common share	$	(0.96	)	$	(0.41	)

Basic weighted-average common shares outstanding	49,131			44,520

Diluted weighted-average common shares outstanding	49,131			44,520

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,
	2016			2015
	(in thousands)
Cash flows from operating activities:
Net loss	$	(47,237	)	$	(18,421	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	26,379			59,004
Deferred income benefit	—			(11,537		)
Impairment of oil and gas properties	10,000			—
Abandonment and impairment of unproved properties	6,906			5,469
Dry hole expense	232			—
Stock-based compensation	3,004			3,427
Amortization of deferred financing costs and debt premium	608			523
Accretion of contractual obligation for land acquisition	—			349
Derivative (gain) loss	1,007			(18,856		)
Derivative cash settlements	7,508			35,466
Other	(116		)	(27		)
Changes in current assets and liabilities:
Accounts receivable	23,044			16,298
Prepaid expenses and other assets	(1,622		)	(1,873		)
Accounts payable and accrued liabilities	(3,141		)	(1,981		)
Settlement of asset retirement obligations	(41		)	(285		)
Net cash provided by operating activities	26,531			67,556
Cash flows from investing activities:
Acquisition of oil and gas properties	(532		)	(11,382		)
Exploration and development of oil and gas properties	(34,822		)	(154,300		)
Natural gas plant capital expenditures	(50		)	(112		)
Increase in restricted cash	(2,533		)	—
Additions to property and equipment - non oil and gas	47			(1,490		)
Net cash used in investing activities	(37,890		)	(167,284		)
Cash flows from financing activities:
Proceeds from credit facility	209,000			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		)
Payment of employee tax withholdings in exchange for the return of common stock	(229		)	(2,127		)
Deferred financing costs	(154		)	(4		)
Net cash provided by financing activities	208,617			167,658
Net change in cash and cash equivalents	197,258			67,930
Cash and cash equivalents:
Beginning of period	21,341			2,584
End of period	$	218,599		$	70,514
Supplemental cash flow disclosure:
Cash paid for interest	$	9,500		$	9,894
Cash paid for income taxes	$	—		$	820
Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition	$	(14,214	)	$	(30,880	)

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 primarily in acquiring, developing, exploiting and producing oil and gas properties. The Company's oil and liquids-weighted assets are concentrated primarily in the Wattenberg Field in Colorado and in the Dorcheat Macedonia Field in southern Arkansas.

NOTE 2 - BASIS OF PRESENTATION

These statements have been prepared in accordance with the Securities and Exchange Commission and accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information with the condensed consolidated balance sheets (“balance sheets”) and the condensed consolidated statements of cash flows (“statements of cash flows”) as of December 31, 2015, being derived from audited financial statements. 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, 2015 (the “2015 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 quarter 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, 2016, and 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 balance sheets include the accounts of the Company 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.

Rocky Mountain Infrastructure, LLC

During the first quarter of 2015, the Company’s wholly owned subsidiary, Bonanza Creek Energy Operating Company, LLC, formed a wholly owned subsidiary, Rocky Mountain Infrastructure, LLC (“RMI”), to hold gathering systems, central production facilities and related infrastructure that service the Wattenberg Field.

Significant Accounting Policies

The significant accounting policies followed by the Company were set forth in Note 1 to the 2015 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 2015 Form 10-K.

Recently Issued Accounting Standards

In January 2016, the FASB issued Update No. 2016-01 – Financial Instruments - Overall to require separate presentation of financial assets and financial liabilities by measurement category and form of financial asset on the balance sheet or the accompanying notes to the financial statements. This authoritative guidance is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. 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 February 2016, the FASB issued Update No. 2016-02 – Leases to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing

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arrangements. This authoritative guidance is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years. The Company is currently evaluating the provisions of this guidance and assessing its impact in relation to the Company's leases.

In March 2016, the FASB issued Update No. 2016-08 – Revenue from Contracts with Customers, which clarifies the implementation guidance on principal versus agent considerations. This authoritative accounting guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2017. The Company has started going through its contracts and is assessing their impact, but does not currently believe this guidance will have a material effect on the Company's financial statements or disclosures.

In March 2016, the FASB issued Update No. 2016-09 – Compensation - Stock Compensation. The update simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This authoritative guidance is effective for fiscal years beginning after December 15, 2016 and interim periods within those fiscal years. 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 - 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. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. Any subsequent decreases to the estimated fair value less the costs to sell impact the measurement of assets held for sale.

As of March 31, 2016, the accompanying balance sheets present $209.4 million of assets held for sale, net of accumulated depreciation, depletion and amortization, which consist of the Company’s ownership interests in RMI, all assets within the Company's Mid-Continent region and all assets in the North Park Basin. There is a corresponding asset retirement obligation liability of approximately $10.8 million for assets held for sale recorded in the asset retirement obligations for assets held for sale financial statement line item in the accompanying balance sheets. There were no other material assets or liabilities associated with the assets held for sale.

During the three months ended March 31, 2016, the Company recorded write-downs to fair value less estimated costs to sell of $10.0 million for its Mid-Continent assets. These write-downs are recorded in the impairment of oil and gas properties line item in the accompanying statements of operations. The Company also received $6.0 million upon termination of the purchase and sale agreement of its RMI interest which is shown in the gain on termination fee line item in the accompanying statements of operations.

The Company determined that none of these potential asset sales qualify for discontinued operations accounting as they did not result in a strategic shift of the Company.

NOTE 4 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses contain the following:

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	As of March 31,		As of December 31,
	2016		2015
	(in thousands)
Drilling and completion costs	$	18,245	$	32,459
Accounts payable trade	484		1,085
Accrued general and administrative cost	4,719		10,643
Lease operating expense	4,336		4,731
Accrued reclamation cost	162		162
Accrued interest	18,669		14,231
Production and ad valorem taxes and other	32,377		33,049
Total accounts payable and accrued expenses	$	78,992	$	96,360

NOTE 5 - LONG-TERM DEBT

Long-term debt consisted of the following:



	As of March 31,		As of December 31,
	2016		2015
	(in thousands)
Revolving credit facility	$	288,000	$	79,000
6.75% Senior Notes due 2021	500,000		500,000
Unamortized premium on 6.75% Senior Notes	6,085		6,392
5.75% Senior Notes due 2023	300,000		300,000
Total long-term debt	$	1,094,085	$	885,392

Credit Facility

The Company’s senior secured revolving Credit Agreement, dated March 29, 2011, as amended (the “revolving credit facility”), provides for borrowings up to $1.0 billion. As of March 31, 2016, and through the filing date of this report, the borrowing base under the revolving credit facility was $475.0 million and equal to the commitment level under the Credit Agreement. The borrowing base is redetermined semiannually, generally occurring no later than May 15 and November 15; we currently expect our next redetermination to occur by May 30, 2016. The revolving credit facility is collateralized by substantially all of the Company’s assets and matures on September 15, 2017. As of March 31, 2016, the Company had $288.0 million outstanding under the revolving credit facility, an outstanding letter of credit of $12.0 million and no available borrowing capacity due to limitations on the incurrence of additional debt set by the indentures for our Senior Notes. As of December 31, 2015, the Company had $79.0 million outstanding under the revolving credit facility with an available borrowing capacity of $384.0 million, if the Company elected to take advantage of the entire borrowing base, after reduction for the outstanding letter of credit of $12.0 million.

The revolving credit facility restricts, among other items, certain dividend payments, additional indebtedness, asset sales, loans, investments and mergers. The revolving credit facility also contains certain financial covenants, which require the maintenance of certain financial and leverage ratios, as defined by the revolving credit facility. The revolving credit facility contains a ratio of maximum senior secured debt to trailing twelve-month EBITDAX that must not exceed 2.50 to 1.00 and a minimum interest coverage ratio that must exceed 2.50 to 1.00. The maximum senior secured debt ratio is calculated by dividing borrowings under the revolving credit facility, balances drawn under letters of credit, and any outstanding second lien debt divided by trailing twelve-month EBITDAX (defined as earnings before interest expense, income tax expense, depreciation, depletion and amortization expense, and exploration expense and other non-cash charges). The minimum interest coverage ratio is calculated by dividing trailing twelve-month EBITDAX by trailing twelve-month interest expense. The revolving credit facility also contains a minimum current ratio covenant of 1.00 to 1.00. The Company was in compliance with all financial and non-financial covenants as of March 31, 2016, and through the filing date of this report.

Senior Unsecured Notes

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The $500.0 million aggregate principal amount of 6.75% Senior Notes that mature on April 15, 2021 (“6.75% Senior Notes”) and the $300.0 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 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 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 certain dividends. The incurrence by the Company or any of the Guarantors of additional indebtedness and letters of credit under the revolving credit facility in an aggregate principal amount at any one time outstanding is not to exceed the greater of (a) $300.0 million or (b) 35% of the Company's Adjusted Consolidated Net Tangible Assets (“ACNTA”). ACNTA is defined as the Company's PV-10 value plus capitalized costs for unproved properties plus consolidated net working capital and other tangible assets.

NOTE 6 - COMMITMENTS AND CONTINGENCIES

Legal Proceedings

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 2015 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, as amended and restated (“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 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.

Total expense recorded for restricted stock for the three month periods ended March 31, 2016 and 2015 was $2.3 million and $2.9 million, respectively. As of March 31, 2016, unrecognized compensation cost was $10.5 million and will be amortized through 2018.

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A summary of the status and activity of non-vested restricted stock for the three months ended March 31, 2016 is presented below.



	Restricted Stock		Weighted- Average Grant-Date Fair Value
Non-vested at beginning of year	731,818		$	29.47
Granted	—		$	—
Vested	(248,447	)	$	33.57
Forfeited	(51,070	)	$	21.81
Non-vested at end of quarter	432,301		$	28.02

Performance Stock Units under the Long Term Incentive Plan

The Company grants performance stock units (“PSUs”) to certain officers under 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 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) although no stock is actually awarded to the participant until the end of the entire 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 same measurement period. The TSR for the Company and each of the peer companies is determined by dividing (A)(i) the average share price for the last 30 trading days of the applicable measuring period, minus (ii) the average share price for the 30 trading days immediately preceding the beginning of the applicable measuring period, by (B) the average share price for the 30 trading days immediately preceding the beginning of the applicable measuring period. The number of earned shares of our common stock will be calculated based on which quartile our TSR percentage ranks as of the end of the annual measurement period relative to the other companies in the comparator group. 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. Compensation expense associated with PSUs is recognized as general and administrative expense over the measurement period.

Total expense recorded for PSUs for the three months ended March 31, 2016 and 2015 was $0.7 million and $0.5 million, respectively. As of March 31, 2016, there was $4.1 million of total unrecognized compensation expense related to unvested PSUs to be amortized through 2019.

A summary of the status and activity of PSUs for the three months ended March 31, 2016 is presented below:



	PSU	Weighted-Average Grant-Date Fair Value
Non-vested at beginning of year ⁽¹⁾	114,833	$	35.27
Granted⁽¹⁾	—	$	—
Vested⁽¹⁾	—	$	—
Forfeited⁽¹⁾	—	$	—
Non-vested at end of quarter⁽¹⁾	114,833	$	35.27

____________________________


(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

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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, 2016 and December 31, 2015 and their classification within the fair value hierarchy:



	As of March 31, 2016
	Level 1		Level 2		Level 3
	(in thousands)
Derivative assets⁽¹⁾	$	—	$	21,052	$	—
Proved properties⁽²⁾	$	—	$	—	$	100,000
Unproved properties⁽²⁾	$	—	$	—	$	178,947



	As of December 31, 2015
	Level 1		Level 2		Level 3
	(in thousands)
Derivative assets⁽¹⁾	$	—	$	29,566	$	—
Proved properties⁽²⁾	$	—	$	—	$	811,913
Unproved properties⁽²⁾	$	—	$	—	$	185,530
Asset retirement obligations⁽³⁾	$	—	$	—	$	2,027

____________________________


(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 Proved Oil and Gas Properties and Unproved Oil and Gas Properties sections below for additional discussion.


(3)	This represents the revision to estimates 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 are validated by

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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 three 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 a relevant estimated selling price is not available, the Company utilizes the income valuation technique discussed above. The Company impaired the Mid-Continent region which had a carrying value of $110.0 million to its estimated fair value, based on the latest received bid, of $100.0 million and recognized an impairment of $10.0 million for the three months ended March 31, 2016. No impairment was recognized for the Rocky Mountain region for the three months ended March 31, 2016. The Company impaired the Mid-Continent region which had a carrying value of $431.2 million to its fair value of $110.0 million and recognized an impairment of $321.2 million for the year ended December 31, 2015. The Company impaired the Rocky Mountain region which had a carrying value of $1.1 billion to its fair value of $701.9 million and recognized an impairment of $419.3 million for the year ended December 31, 2015.

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, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If a relevant 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 non-core acreage in the Wattenberg Field due to leases expiring which had a carrying value of $185.8 million to their fair value of $178.9 million and recognized an impairment of unproved properties of $6.9 million for the three months ended March 31, 2016. The Company impaired non-core acreage in the Wattenberg Field due to leases expiring, which had a carrying value of $210.3 million to their fair value of $185.5 million and recognized an impairment of unproved properties for the year ended December 31, 2015 of $24.8 million. The Company also fully impaired the North Park Basin in 2015, due to a change in the Company’s development plan, recognizing an impairment of unproved properties of $8.7 million.

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, 2016. The Company had $2.0 million of asset retirement obligations recorded at fair value as of December 31, 2015.

Long-term Debt

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As of March 31, 2016, the Company had $500.0 million of outstanding 6.75% Senior Notes and $300.0 million of outstanding 5.75% Senior Notes, all of which are unsecured senior obligations. The 6.75% Senior Notes are recorded at cost, plus the unamortized premium, on the accompanying balance sheets at $506.1 million and $506.4 million as of March 31, 2016 and December 31, 2015, respectively. The fair value of the 6.75% Senior Notes as of March 31, 2016 and December 31, 2015 was $141.3 million and $301.3 million, respectively. The 5.75% Senior Notes are recorded at cost on the accompanying balance sheets at $300.0 million as of March 31, 2016 and December 31, 2015. The fair value of the 5.75% Senior Notes as of March 31, 2016 and December 31, 2015 was $81.8 million and $163.1 million, respectively. The Senior Notes are measured using Level 1 inputs based on a secondary market trading price. The Company’s revolving credit facility approximates fair value as the applicable interest rates are floating. The outstanding balance under the revolving credit facility as of March 31, 2016 and December 31, 2015 was $288.0 million and $79.0 million, respectively.

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 oil swap arrangements and puts, none of which qualify as having hedging relationships. Effective March 10, 2016, the Company converted its three-way collars into fixed price swaps and puts.

As of March 31, 2016, and as of the filing date of this report, the Company had the following derivative commodity contracts in place:



Settlement Period	Derivative Instrument	Total Volumes (Bbls per day)	Average Fixed Price	Fair Market Value of Assets
				(in thousands)
Oil
2Q 2016	Swap	3,103	$49.87	$	2,815
3Q 2016	Swap	2,704	$51.78	2,434
4Q 2016	Swap	2,303	$52.83	2,062
2Q 2016	Put	5,430	$51.01	5,548
3Q 2016	Put	4,733	$51.01	4,409
4Q 2016	Put	4,031	$51.01	3,784

Total				$	21,052

Derivative Assets Fair Value

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

The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of March 31, 2016 and December 31, 2015:



	As of March 31, 2016
	Balance Sheet Location	Fair Value
		(in thousands)
Derivative Assets:
Commodity contracts	Current assets	$	21,052
Commodity contracts	Noncurrent assets	—
Derivative Liabilities:
Commodity contracts	Current liabilities	—
Commodity contracts	Long-term liabilities	—
Total derivative asset		$	21,052

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	As of December 31, 2015
	Balance Sheet Location	Fair Value
		(in thousands)
Derivative Assets:
Commodity contracts	Current assets	$	29,566
Commodity contracts	Noncurrent assets	—
Derivative Liabilities:
Commodity contracts	Current liabilities	—
Commodity contracts	Long-term liabilities	—
Total derivative asset		$	29,566

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



	Three months ended March 31,
	2016			2015
	(in thousands)
Derivative cash settlement gain:
Oil contracts	$	7,508		$	34,791
Gas contracts	—			675
Total derivative cash settlement gain⁽¹⁾	$	7,508		$	35,466

Change in fair value loss	$	(8,515	)	$	(16,610	)

Total derivative gain (loss)⁽¹⁾	$	(1,007	)	$	18,856

_______________________________


(1)	Total derivative gain (loss) and the derivative cash settlement gain for the three months ended March 31, 2016 and 2015 is reported in the derivative (gain) loss line item and derivative cash settlements line item on the accompanying 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 and losses to common shareholders only.

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 zero to two times 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 loss per basic and diluted shares for the three month periods ended March 31, 2016 and 2015.



	Three Months Ended March 31,
	2016			2015
	(in thousands, except per share amounts)
Net loss	$	(47,237	)	$	(18,421	)
Less: undistributed loss to unvested restricted stock	—			—
Undistributed loss to common shareholders	(47,237		)	(18,421		)
Basic net loss per common share	$	(0.96	)	$	(0.41	)
Diluted net loss per common share	$	(0.96	)	$	(0.41	)

Weighted-average shares outstanding - basic	49,131			44,520
Add: dilutive effect of contingent PSUs	—			—
Weighted-average shares outstanding - diluted	49,131			44,520

The Company was in a net loss position for the three months ended March 31, 2016 and 2015, which made any potentially dilutive shares anti-dilutive. There were no dilutive shares for the three months ended March 31, 2016 and 147,786 dilutive shares that were anti-dilutive for the three months ended March 31, 2015. The participating shareholders are not contractually obligated to share in the losses of the Company, and therefore, the entire net loss is allocated to the outstanding common shareholders.

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 $202.7 million after deducting underwriter discounts, commissions and offering expenses of approximately $6.6 million. The Company used a portion of the net proceeds to repay all of the then outstanding borrowings under its revolving credit facility and 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, 2016 and 2015, the effective tax rate was 0.0% and 38.5%, respectively. As of December 31, 2015 a full valuation allowance was placed against the net deferred tax assets. The Company’s current rate differs from the U.S. statutory income tax rate due to the full valuation allowance being placed against the net deferred tax assets as of March 31, 2016.

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.

As of March 31, 2016, 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 taken thus far in 2016. 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, and any such adjustments would very likely adjust only net operating loss carry forward.

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

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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, 2015, 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 energy company engaged in the acquisition, exploration, development, and production of onshore 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 and the Dorcheat Macedonia Field in southern Arkansas. 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, established reserves and prospective drilling opportunities, which allows for predictable production and reserve growth.

Despite the current depressed commodity pricing environment, we are committed to preserving value by maximizing the cash flows from our existing production, optimizing the Company’s liquidity and positioning existing leasehold for increased development activity when appropriate commodity price signals are observed. Our liquidity position strategies include potential asset sales and joint ventures, debt restructurings, the issuance of new debt or equity and the conservation of our liquid assets. Furthermore, we scaled back our capital expenditures for 2016 to match the current commodity pricing environment, as well as took steps to reduce our future operating and corporate costs. During the first quarter 2016, we took measures to reduce corporate costs by reducing headcount resulting in a one-time payment of $2.2 million and an annual expected reduction in general and administrative expense and lease operating costs of $7.6 million and $3.1 million, respectively.

We have become more efficient and negotiated with our service providers to reduce lease operating costs, drilling and completion costs and gathering and processing expenses. We will continue to pursue operating efficiencies and procurement savings although we expect the amount of future decreases will not be as significant as those achieved during 2015 and the first quarter of 2016, as margins in the industry are already compressed.

Senior Management Changes

The Company's Executive Vice President, General Counsel and Secretary, Christopher I. Humber, and its Executive Vice President and Chief Financial Officer, William J. Cassidy, separated from the Company effective March 30, 2016 and March 31, 2016, respectively. During this interim period we have contracted external counsel and named the Company's Chief Accounting Officer as the acting principal financial officer.

Financial and Operating Results

Our financial and operational results, most of which were impacted by depressed oil, natural gas and NGL prices, include:


•	Net loss of $47.2 million, as compared to a net loss of $18.4 million for the first quarter 2015;


•	Drew down $209.0 million on our revolving credit facility during the first quarter of 2016 to mitigate potential liquidity reductions;


•	Total liquidity as of March 31, 2016 of $218.6 million, consisting of a period-end cash balance;


•	Decrease in sales volumes of 11% to 2,213.1 MBoe in the first quarter of 2016 from 2,475.8 MBoe in the first quarter of 2015, with oil and NGL production representing approximately 75% of total sales volumes in the first quarter of 2016;


•	Cash operating costs, which consist of lease operating expense, gas plant and midstream operating expense, severance and ad valorem taxes, and the cash portion of general and administrative expense, per barrel decreased by $0.06 per Boe to $15.78 per Boe or $1.86 per Boe to $13.98 per Boe for adjusted cash operating cash, which

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excludes severance and RMI lease operating expenses from the first quarter of 2016 for comparison purposes to the first quarter of 2015;


•	Beat the low-end of combined lease operating expense guidance for the first quarter 2016 by 21%;


•	Drilled nine and completed 17 gross wells within our Rocky Mountain region during the first quarter of 2016; and


•	Capital expenditures of $20.7 million, as compared with $123.4 million for the first quarter of 2015.

Outlook for 2016

Beginning in 2014, the oil and nature gas industry began to experience a sharp decline in commodity prices. Caused in part by global supply and demand imbalances and an oversupply of natural gas in the United States, the pricing declines have extended into 2016 and the timing of any rebound is uncertain. Low commodity prices resulted in a reduction of our revenues, profitability, cash flows, proved reserve values and our stock price. If the industry downturn continues for an extended period or becomes more severe, we could experience additional impairments and further material reductions in revenues, profitability, cash flows, proved reserves and declines in our stock price.

We estimate our capital expenditures in the Wattenberg Field for 2016 to range from $30.0 million to $40.0 million used to drill nine and complete twelve wells, $3.5 million in our Mid-Continent region to recomplete 38 wells to maintain value as we move towards the potential sale of assets, and $1.5 million for corporate expenditures, the majority of which was incurred in the first quarter. We currently do not have any active drilling planned for the remainder of 2016. Consequently we expect our production will decline in line with our normal decline curves, and we will experience further reductions in revenues, profitability and cash flows. The ultimate amount of capital we will expend may fluctuate materially based on, among other things, market conditions, commodity prices, strategic divestitures, the continuation of drilling as the year progresses and changes in the borrowing base under our revolving credit facility.

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Results of Operations

Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015

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



		Three Months Ended March 31,
								Percent
		2016		2015		Change		Change
		(In thousands, except percentages)
Revenues:
Crude oil sales	$	34,673	$	59,420	$	(24,747	)	(42	)%
Natural gas sales		4,614		7,988		(3,374	)	(42	)%
Natural gas liquids sales		4,887		5,668		(781	)	(14	)%
Product revenue	$	44,174	$	73,076	$	(28,902	)	(40	)%

Sales Volumes:
Crude oil (MBbls)		1,283.3		1,490.5		(207.2	)	(14	)%
Natural gas (MMcf)		3,320.6		3,506.9		(186.3	)	(5	)%
Natural gas liquids (MBbls)		376.4		400.8		(24.4	)	(6	)%
Crude oil equivalent (MBoe)⁽¹⁾		2,213.1		2,475.8		(262.7	)	(11	)%

Average Sales Prices (before derivatives)⁽²⁾:
Crude oil (per Bbl)	$	27.02	$	39.87	$	(12.85	)	(32	)%
Natural gas (per Mcf)	$	1.39	$	2.28	$	(0.89	)	(39	)%
Natural gas liquids (per Bbl)	$	12.98	$	14.14	$	(1.16	)	(8	)%
Crude oil equivalent (per Boe)⁽¹⁾	$	19.96	$	29.52	$	(9.56	)	(32	)%

Average Sales Prices (after derivatives)⁽²⁾:
Crude oil (per Bbl)	$	32.87	$	63.21	$	(30.34	)	(48	)%
Natural gas (per Mcf)	$	1.39	$	2.47	$	(1.08	)	(44	)%
Natural gas liquids (per Bbl)	$	12.98	$	14.14	$	(1.16	)	(8	)%
Crude oil equivalent (per Boe)⁽¹⁾	$	23.35	$	43.84	$	(20.49	)	(47	)%

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

(2)

The derivatives economically hedge the price we receive for crude oil and natural gas. For the three months ended March 31, 2016 and 2015, the derivative cash settlement gain for oil contracts was $7.5 million and $34.8 million, respectively, and the derivative cash settlement gain for gas contracts was zero and $0.7 million, respectively. Please refer to Note 9 - Derivatives of Part I, Item 1 of this report for additional disclosures.

Revenues decreased by 40%, to $44.2 million, for the three months ended March 31, 2016 compared to $73.1 million for the three months ended March 31, 2015 largely due to a 32% decrease in oil equivalent pricing, coupled with an 11% decrease in sales volumes. The decreased volumes are a direct result of less capital spent for drilling and completion during the last three quarters of 2015 and the first quarter of 2016. During the period from March 31, 2015 through March 31, 2016, we drilled 63 and completed 80 gross wells in the Rocky Mountain region and drilled 15 and completed 16 gross wells in the Mid-Continent region, as compared to the period from March 31, 2014 through March 31, 2015, where 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
		2016		2015		Change		Change
		(In thousands, except percentages)
Expenses:
Lease operating expense	$	13,298	$	16,973	$	(3,675	)	(22	)%
Gas plant and midstream operating expense		3,789		2,291		1,498		65	%
Severance and ad valorem taxes		3,154		6,496		(3,342	)	(51	)%
Exploration		266		498		(232	)	(47	)%
Depreciation, depletion and amortization		26,379		59,004		(32,625	)	(55	)%
Impairment of oil and gas properties		10,000		—		10,000		100	%
Abandonment and impairment of unproved properties		6,906		5,469		1,437		26	%
General and administrative		17,685		16,872		813		5	%
Operating Expenses	$	81,477	$	107,603	$	(26,126	)	(24	)%

Selected Costs ($ per Boe):
Lease operating expense	$	6.01	$	6.86	$	(0.85	)	(12	)%
Gas plant and midstream operating expense		1.71		0.93		0.78		84	%
Severance and ad valorem taxes		1.43		2.62		(1.19	)	(45	)%
Exploration		0.12		0.20		(0.08	)	(40	)%
Depreciation, depletion and amortization		11.92		23.83		(11.91	)	(50	)%
Impairment of oil and gas properties		4.52		—		4.52		100	%
Abandonment and impairment of unproved properties		3.12		2.21		0.91		41	%
General and administrative		7.99		6.81		1.18		17	%
Operating Expenses	$	36.82	$	43.46	$	(6.64	)	(15	)%

Lease operating expense. Our lease operating expense decreased $3.7 million, or 22%, to $13.3 million for the three months ended March 31, 2016 from $17.0 million for the three months ended March 31, 2015 and decreased on an equivalent basis from $6.86 per Boe to $6.01 per Boe. The Company reduced operating costs and negotiated contract reductions resulting in decreased pumping and gauging costs of $1.3 million and well servicing costs of $2.1 million during the three months ended March 31, 2016 when compared to the same period in 2015.

Gas plant and midstream operating expense. Our midstream operating expense increased $1.5 million, or 65%, to $3.8 million for the three months ended March 31, 2016 from $2.3 million for the three months ended March 31, 2015 and increased on an equivalent basis from $0.93 per Boe to $1.71 per Boe. The increase in aggregate midstream operating expense and equivalent basis is due to RMI's operations beginning in the second quarter of 2015.

Severance and ad valorem taxes. Our severance and ad valorem taxes decreased 51% to $3.2 million for the three months ended March 31, 2016 from $6.5 million for the three months ended March 31, 2015. Severance and ad valorem taxes primarily correlate to revenue. Revenues decreased by 40% for the three months ended March 31, 2016 when compared to the same period in 2015 causing the severance and ad valorem taxes to decrease.

Exploration. Our exploration expense decreased $0.2 million to $0.3 million during the three months ended March 31, 2016 when compared to the same period in 2015. During the three months ended March 31, 2016, we incurred $0.2 million of charges for exploratory wells which we were unable to assign economic proved reserves. During the three months ended March 31, 2015, we incurred $0.5 million in delay rentals.

Depreciation, depletion and amortization. Our depreciation, depletion and amortization expense decreased $32.6 million, or 55%, to $26.4 million for the three months ended March 31, 2016 from $59.0 million for the three months ended

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March 31, 2015 and decreased on an equivalent basis from $23.83 per Boe to $11.92 per Boe. The decrease in the first quarter of 2016 is primarily due to the proved property impairments realized in the fourth quarter of 2015 and the cessation of depletion for assets classified as held for sale late in 2015.

Impairment of oil and gas properties. Our impairment of proved properties increased 100% to $10.0 million for the three months ended March 31, 2016 when compared to the same period in 2015. The Company impaired its Dorcheat Field to the latest received bid price during the three months ended March 31, 2016. There were no proved property impairments for the three months ended March 31, 2015.

Abandonment and impairment of unproved properties. Our abandonment and impairment of unproved properties increased 26% to $6.9 million for the three months ended March 31, 2016 when compared to the three months ended March 31, 2015. The Company incurred $6.9 million and $5.5 million of impairment charges relating to non-core leases expiring within the Wattenberg Field during the three months ended March 31, 2016 and 2015, respectively.

General and administrative. Our general and administrative expense increased 5%, to $17.7 million for the three months ended March 31, 2016 from $16.9 million for the comparable period in 2015 and increased on an equivalent basis to $7.99 per Boe from $6.81 per Boe. The increase in general and administrative expense was due to the payment of $1.6 million for executive severance and $0.6 million of severance for other employees who were part of the reduction in workforce offset by a decrease in accrued bonuses of $1.1 million between comparable periods.

Derivative gain (loss). Our derivative gain decreased $19.9 million to a $1.0 million loss for the three month period ended March 31, 2016 when compared to the same period in 2015. The decrease is related to a reduction in hedged volumes during the three months ended March 31, 2016 when compared to the three months ended March 31, 2015. Please refer to Note 9 - Derivatives above for additional discussion.

Interest expense. Our interest expense for the three months ended March 31, 2016 increased 2%, to $14.5 million compared to $14.2 million for the three months ended March 31, 2015. Interest expense, including amortization of the premium and financing costs on the Senior Notes was $13.0 million for the three month periods ended March 31, 2016 and 2015. Average debt outstanding for the three months ended March 31, 2016 was $950.2 million as compared to $821.7 million for the comparable period in 2015.

Income tax benefit. Our estimate for federal and state income tax benefit for the three months ended March 31, 2016 was zero as compared to $11.5 million for the three months ended March 31, 2015. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. Our effective tax rates for the three month periods ended March 31, 2016 and 2015 were 0.0% and 38.5%, respectively. As of December 31, 2015 a full valuation allowance was placed against the net deferred tax assets. The Company’s effective tax rate differs from the U.S. statutory income tax rate due to a full valuation allowance being placed against net deferred tax assets as of December 31, 2015.

Liquidity and Capital Resources

We fund our operations, capital expenditures and working capital requirements with cash flows from our operating activities, borrowings under our revolving credit facility, divestitures of assets and by accessing the debt and capital markets.

We currently anticipate funding the remainder of our 2016 operations with operating cash flows and our outstanding revolving credit facility balance, until such point that we execute upon a strategic divestiture or commodity prices rebound. Due in part to the planned cessation of our drilling program for the remainder of 2016, we believe that we will have sufficient access to sources of cash to fund our business for at least the next twelve months and until such point that commodity prices rebound or we execute upon one or more of our 2016 liquidity strategies, but market conditions are variable and volatile and actual cash flows could be insufficient.

To the extent actual operating results are below our anticipated results, we are unsuccessful in our divestiture efforts or our borrowing base under our revolving credit facility is redetermined at a lower amount requiring a significant repayment, our liquidity would be adversely affected. Additionally, as a result of depressed commodity prices, we anticipate that our borrowing base will be reduced at our next redetermination, which is expected to occur by May 30, 2016. Depending on its magnitude, a reduction in our borrowing base could result in material repayment obligations to our secured lenders, resulting in less funds for general corporate expenditures, less availability for our drilling program and reduced availability to fund other subordinate corporate obligations.

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As of March 31, 2016, our borrowing base was $475.0 million, of which we had $288.0 million outstanding on our revolving credit facility, a $12.0 million letter of credit issued, and no available borrowing capacity due to limitations in the indenture of our Senior Notes. Please refer to Note 5 - Long-term debt above for additional discussion. Our weighted-average interest rates (excluding amortization of deferred financing costs and the accretion of our contractual obligation for land acquisition) on borrowings from our revolving credit facility were 2.34% and 1.67%, respectively, for the three months ended March 31, 2016 and 2015. Our commitment fees were $0.4 million and $0.5 million, respectively, for the three months ended March 31, 2016 and 2015.

On February 6, 2015, the Company completed a public offering of 8,050,000 shares of its common stock generating net proceeds of $202.7 million after deducting underwriter discounts, commissions and offering expenses of approximately $6.6 million. The Company used a portion of the net proceeds to repay all of the then outstanding borrowings under its revolving credit facility and used the remaining net proceeds for general corporate purposes, including its drilling and development program and other capital expenditures.

For the remainder of 2016, we have hedged oil swaps and puts with average quarterly volumes ranging from 2,303 to 3,103 Bbls per day and 4,031 to 5,430 Bbls per day, respectively, with average fixed prices ranging from $49.87 to $52.83 per Bbl and $51.01 per Bbl, respectively. Our swaps represent approximately 36% of our anticipated production for the remainder of 2016. We expect that our commodity derivative positions will provide partial stabilization of our expected cash flows from operations. Please refer to Note 9 - Derivatives above for a summary of derivatives in place and Item 3. Quantitative and Qualitative Disclosures About Market Risks below for additional discussion.

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



	Three Months Ended March 31,
	2016			2015
	(in thousands)
Net cash provided by operating activities	$	26,531		$	67,556
Net cash used in investing activities	(37,890		)	(167,284		)
Net cash provided by financing activities	208,617			167,658
Cash and cash equivalents	218,599			70,514
Acquisition of oil and gas properties	532			11,382
Exploration and development of oil and gas properties	34,822			154,300

Cash flows provided by operating activities

During the three month period ended March 31, 2016, we generated $26.5 million of cash provided by operating activities, a decrease of $41.0 million from the comparable period in 2015. The decrease in cash flows from operating activities resulted primarily from a $28.9 million decrease in revenues due to a 32% decrease in oil equivalent pricing and a 11% decrease in sales volumes and a $28.0 million decrease in derivative cash settlements during the three months ended March 31, 2016 as compared to the three months ended March 31, 2015. See Results of 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 are the primary use of our capital resources. Net cash used in investing activities for the three months ended March 31, 2016 decreased $129.4 million as compared to the same period in 2015. For the three months ended March 31, 2016, cash used for the development of oil and natural gas properties was $34.8 million. For the three months ended March 31, 2015, cash used for the acquisition of oil and gas properties was $11.4 million and cash used for the development of oil and natural gas properties was $154.3 million.

Cash flows provided by financing activities

Net cash provided by financing activities for the three months ended March 31, 2016 increased $41.0 million compared to the same period in 2015. The increase was primarily due to borrowings in excess of payments on our revolving credit facility increasing by $242.0 million for the three months ended March 31, 2016, when compared to the same period in 2015 offset by net proceeds from the sale of common stock of $202.8 million that occurred in 2015.

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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 Part II, Item 7 of our 2015 Form 10-K.

Effects of Inflation and Pricing

Inflation in the United States increased slightly over the past few years, which did not have a material impact on

our results of operations for the periods ended March 31, 2016 and 2015. Although the impact of inflation has been

relatively 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, asset retirement obligations, 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. Given the continued decline in oil and gas prices, we would anticipate that costs of materials and services to remain at the lower levels we have experienced in the last year.

Off-Balance Sheet Arrangements

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

Contractual Obligations

There were no material changes in our contractual obligations and other commitments as disclosed in our 2015 Form 10-K.

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 (the “Exchange Act”). 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:


•	the Company's business and liquidity strategies;


•	reserves estimates;


•	estimated sales volumes for 2016;


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


•	ability to consummate certain strategic divestitures;


•	impact of proposed strategic divestitures;

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•	the Wattenberg Field being a premier oil and resource play in the United States;


•	anticipated continued reduction of costs of materials and services;


•	anticipated reduction of general and administrative expense and lease operating costs as a result of the measures taken in first quarter 2016 to reduce headcount;


•	ability to satisfy obligations related to ongoing operations;


•	impact of lower commodity prices;


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


•	our estimated revenues and losses;


•	the timing and success of specific projects;


•	outcomes and effects of litigation, claims and disputes;


•	impact of recently issued accounting pronouncements;


•	the Company’s tax position and future tax adjustments;


•	our financial position;


•	the amount and availability of our borrowing base under our revolving credit facility and the effect of future borrowing base redeterminations;


•	impacts from the divestiture of any of our assets;


•	our cash flow and liquidity;


•	our future production;


•	impact of commodity derivative positions;


•	2016 outlook;


•	impacts of the Company's workforce reduction; 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 2015 Form 10-K;


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


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

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


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


•	the presence or recoverability of estimated oil and natural gas reserves and the actual future sales volume 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;


•	lease stipulations;


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


•	our 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;


•	our 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;


•	availability of funds to operate our business if there is a significant further reduction in our borrowing base;


•	the ability to realize recorded values for our assets held for sale; 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.

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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 could cause our actual results to differ materially from our expectations under Part II, Item 1A. Risk Factors and Part II, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Oil and Natural Gas Price Risk

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 and natural gas, 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, local and global politics, 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 derivative contracts for oil using NYMEX futures or over-the-counter derivative financial instruments with counterparties who we believe are well-capitalized and 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 or otherwise fail to perform. To the extent that we engage in derivative contracts, 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 three counterparties, all of which are lenders under our revolving credit facility. If these counterparties fail to perform their 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 requires us to make payment for the settlement of our 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 9 - Derivatives of Part I, Item 1 of this report for a derivative summary table.

Interest Rates

As of March 31, 2016, we had $288.0 million outstanding under our revolving credit facility. Borrowings under our revolving credit facility bear interest at a fluctuating rate that is tied to an adjusted bank base rate or London Interbank Offered Rate, at our option. Any increases in these interest rates can have an adverse impact on our results of operations and cash flow.

Counterparty and Customer Credit Risk

In connection with our derivatives activity, we have exposure to financial institutions in the form of derivative transactions. Three lenders under our revolving credit facility are counterparties on our derivative instruments currently in place and have investment grade credit ratings. We expect that any future derivative transactions we enter into will be with these or other lenders under our revolving credit facility that will carry an investment grade credit rating.

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

Marketability of Our Production

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

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

There have not been material changes to the interest rate risk analysis or oil and gas price sensitivity analysis disclosed in our 2015 Form 10-K.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of March 31, 2016. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that 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 officer and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of March 31, 2016, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. To assist management, we have established an internal audit function to verify and monitor our internal controls and procedures. The Company’s internal control system is supported by written policies and procedures, contains self-monitoring mechanisms and is audited by the internal audit function. Appropriate actions are taken by management to correct deficiencies as they are identified.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended March 31, 2016 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

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

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Item 1A. Risk Factors.

Our business faces many risks. Any of the risk factors discussed in this report or our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation. For a discussion of our potential risks and uncertainties, see the information in Part I, Item 1A., Risk Factors, in our 2015 Form 10-K. There have been no material changes to our risk factors from those described in our 2015 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 March 31, 2016.

Issuer purchases of equity securities. The following table contains information about acquisitions of our equity securities during the three month period ended March 31, 2016.



					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
January 1, 2016 - January 31, 2016	1,394	$	3.37	—	—
February 1, 2016 - February 29, 2016	18,140	$	1.77	—	—
March 1, 2016 - March 31, 2016	89,899	$	2.05	—	—
Total	109,433	$	2.02	—	—

____________________________________________________________________________

(1)

Represent shares that employees surrendered back to us that equaled in value the amount of taxes required for payroll tax withholding obligations upon the vesting of restricted stock awards and performance stock units. 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.

Our revolving credit facility and Senior Notes provide for restrictions on the payment of certain dividends.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.

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Item 6. Exhibits.



Exhibit No.		Description of Exhibit
10.1†		Separation and General Release Agreement dated March 23, 2016 by and between Bonanza Creek Energy, Inc. and William J. Cassidy.

10.2†		Separation and General Release Agreement dated March 22, 2016 by and between Bonanza Creek Energy, Inc. and Christopher I. Humber.

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

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

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

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

101†		The following materials from the Bonanza Creek Energy, Inc. Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, formatted in XBRL (Extensible Business Reporting Language) include (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations and Comprehensive Income, (iii) the Condensed Consolidated Statements of Cash Flows and (iv) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.

† Filed or furnished herewith

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SIGNATURES

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



		BONANZA CREEK ENERGY, INC.

Date:	May 5, 2016	By:	/s/ Richard J. Carty
			Richard J. Carty
			President and Chief Executive Officer
			(principal executive officer)


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