CIVITAS RESOURCES, INC. - Quarter Report: 2012 March (Form 10-Q)

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

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

 

For the quarterly period ended March 31, 2012

 

or

 

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

 

For the transition period from                    to                      

 

Commission File Number:                       

 

Bonanza Creek Energy, Inc.

(Exact name of registrant as specified in its charter)

 

 

(720) 440-6100

(Registrant’s telephone number, including area code)

 

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

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  x Yes  o No

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

 

SEC 1296 (01-12) Potential persons who are to respond to the collection of information contained in this form are not required to respond unless the form displays a currently valid OMB control number.

 

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. 39,477,584 shares of common stock were outstanding as of April 30, 2012.

 

 

 

PART I - FINANCIAL INFORMATION

 

Item 1.    Financial Statements.

 

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

 

(unaudited)

 

		March 31, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	—		$	2,089,674
Accounts receivable:
Oil and gas sales		30,419,410			17,850,719
Other		7,670,882			5,696,825
Prepaid expenses and other		1,974,266			1,868,016
Inventory of oilfield equipment		2,605,286			3,324,368
Derivative asset		885,490			1,297,403
Total current assets		43,555,334			32,127,005
OIL AND GAS PROPERTIES—using the successful efforts method of accounting:
Proved properties		573,026,909			560,938,785
Unproved properties		15,881,225			15,880,716
Wells in progress		68,750,476			23,950,340
		657,658,610			600,769,841
Less: accumulated depreciation, depletion and amortization		(41,241,325		)	(30,123,343		)
		616,417,285			570,646,498
NATURAL GAS PLANT		60,934,159			56,910,232
Less: accumulated depreciation		(1,781,159		)	(1,286,129		)
		59,153,000			55,624,103
PROPERTY AND EQUIPMENT		2,578,476			1,983,037
Less: accumulated depreciation		(224,228		)	(128,731		)
		2,354,248			1,854,306
LONG-TERM DERIVATIVE ASSET		336,597			678,474
OTHER ASSETS, net		3,259,565			3,418,626
TOTAL ASSETS		$	725,076,029		$	664,349,012
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued expenses		$	51,556,907		$	27,068,326
Oil and gas revenue distribution payable		7,963,125			6,185,983
Derivative liability		7,355,076			5,276,633
Total current liabilities		66,875,108			38,530,942
LONG-TERM LIABILITIES:
Bank revolving credit		21,600,000			6,600,000
Ad valorem taxes		5,081,576			3,014,023
Derivative liability		3,122,773			2,579,175
Deferred income taxes, net		84,953,664			79,603,633
Asset retirement obligations		6,244,675			6,039,723
TOTAL LIABILITIES		187,877,796			136,367,496
COMMITMENTS AND CONTINGENCIES (Note 6)
STOCKHOLDERS’ EQUITY:
Preferred stock, $.001 par value, 25,000,000 shares authorized, 0 outstanding		—			—
Common stock, $.001 par value, 225,000,000 shares authorized, 39,477,584 issued and outstanding		39,478			39,478
Additional paid-in capital		516,083,147			515,412,583
Retained earnings		21,075,608			12,529,455
Total stockholders’ equity		537,198,233			527,981,516
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	725,076,029		$	664,349,012

 

See accompanying notes to these consolidated financial statements.

 

2

 

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF OPERATIONS

 

(unaudited)

 

		Quarter Ended March 31, 2012			Quarter Ended March 31, 2011
NET REVENUES
Oil and gas sales		$	49,542,329		$	22,212,617
OPERATING EXPENSES:
Lease operating		7,775,074			4,614,024
Severance and ad valorem taxes		3,691,435			1,052,919
Exploration		1,200,725			525,464
Depreciation, depletion and amortization		11,827,980			6,387,444
General and administrative (including $670,564 and $—, respectively, of stock compensation)		5,964,718			2,238,554
Total operating expenses		30,459,932			14,818,405
INCOME FROM OPERATIONS		19,082,397			7,394,212
OTHER INCOME (EXPENSE):
Other income (loss)		(37,727		)	67,946
Interest expense		(561,516		)	(712,772		)
Unrealized (loss) in fair value of commodity derivatives		(3,375,831		)	(5,454,546		)
Realized (loss) in fair value of commodity derivatives		(1,211,139		)	(775,920		)
Total other income (loss)		(5,186,213		)	(6,875,292		)
INCOME BEFORE TAXES		13,896,184			518,920
Deferred income taxes (Note 9)		(5,350,031		)	(192,000		)
NET INCOME		$	8,546,153		$	326,920
BASIC AND DILUTED INCOME PER SHARE		$	0.22		$	0.01
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—BASIC AND DILUTED		39,477,584			29,122,521

 

See accompanying notes to these consolidated financial statements.

 

3

 

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(unaudited)

 

		Quarter Ended March 31, 2012			Quarter Ended March 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	8,546,153		$	326,920
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		11,827,980			6,387,444
Deferred income taxes		5,350,031			192,000
Non-cash stock compensation		670,564			—
Amortization of deferred financing costs		288,494			201,782
Valuation (increase) decrease in commodity derivatives		3,375,831			5,454,546
Other		45,000			(1,751		)
(Increase) decrease in operating assets:
Accounts receivable		(14,542,748		)	(547,762		)
Prepaid expenses and other assets		(106,250		)	(348,998		)
(Decrease) increase in operating liabilities:
Accounts payable and accrued liabilities		2,230,988			(1,445,852		)
Settlement of asset retirement obligations		(749		)	(32,200		)
Net cash provided by operating activities		17,685,294			10,186,129
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of oil and gas properties		(294,127		)	(46,378		)
Exploration and development of oil and gas properties		(27,464,392		)	(12,053,184		)
Natural gas plant capital expenditures		(6,246,577		)	(5,353,380		)
Proceeds from note receivable		—			986,906
Increase in restricted cash		(139,375		)	—
Additions to property and equipment—non oil and gas		(595,439		)	(65,229		)
Net cash used in investing activities		(34,739,910		)	(16,531,265		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in bank revolving credit		15,000,000			71,900,000
Payment on bank revolving credit		—			(63,800,000		)
Deferred financing costs		(35,058		)	(986,816		)
Net cash provided by financing activities		14,964,942			7,113,184
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(2,089,674		)	768,048
CASH AND CASH EQUIVALENTS:
Beginning of period		2,089,674			—
End of period		$	—		$	768,048
SUPPLEMENTAL CASH FLOW DISCLOSURE:
Cash paid for interest		$	243,201		$	609,196
Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition		$	26,102,288		$	2,092,959

 

See accompanying notes to these consolidated financial statements.

 

4

 

Bonanza Creek Energy, Inc.

Notes to the Consolidated Financial Statements as of March 31, 2012 (unaudited)

 

1. ORGANIZATION AND BUSINESS:

 

On December 23, 2010, Bonanza Creek Energy, Inc., a Delaware corporation formed on December 2, 2010 (the “Company” or “BCEI”), participated in the following transactions which were accomplished simultaneously:

 

(1)                              The contribution by Bonanza Creek Energy Company, LLC (“BCEC”) of all of its ownership in Bonanza Creek Energy Operating Company, LLC (a wholly owned subsidiary) to BCEI and assumption by BCEI of BCEC’s remaining debt (as described below) in exchange for a 21.55% ownership interest of BCEI. BCEC had no other significant assets or subsidiaries at such time. BCEC was an operating oil and gas company that was initially founded in 2006;

 

(2)                                  The sale of $265 million of common stock of BCEI which constituted an ownership interest of 72.68% of BCEI to Project Black Bear LP (“Black Bear”), an entity advised by West Face Capital Inc. (“West Face Capital”), and to certain clients of Alberta Investment Management Corporation (“AIMCo”); and

 

(3)                                  The exchange of shares of 5.77% of BCEI’s common stock together with $59 million in cash (which came from the $265 million sale of common stock of BCEI described in (2) above), for all of the equity interests of Holmes Eastern Company, LLC, a Delaware limited liability company (“HEC”), that was majority owned by a minority member of Bonanza Creek Oil Company, LLC (“BCOC”).  BCOC was the predecessor of BCEC and owned 29.9% of BCEC on a fully diluted basis at the time of such transaction. HEC was initially formed in 2009 and has been an operating oil and gas exploration and production business since its formation.

 

The BCEC ownership (21.55%) of BCEI was subsequently distributed to or for the benefit of BCEC’s members based on management’s estimate of fair value of the BCEI shares received by BCEC to holders of the equity interests of BCEC in connection with the redemption of BCEC’s equity and BCEC’s dissolution to of for the benefit of:

 

(1)                                  BCOC in the amount of 5.5% (for its Series A Units of BCEC);

 

(2)                                  D.E. Shaw Laminar Portfolios, L.L.C. (“Laminar”) in the amount of 12.91% (for its Series A Units of BCEC); and

 

(3)                                  The management and employees of BCEC, in the amount of 3.14% (for their Class B Units of BCEC).

 

Cash proceeds of approximately $182 million were used to retire BCEC’s second lien term loan, senior subordinated notes and a related party note payable, and to reduce the outstanding principal balance on BCEC’s bank revolving credit facility by $29 million thereby reducing the balance outstanding to approximately $55.4 million as of December 31, 2010. This loan at the same time was assumed by BCEI.

 

The Company is engaged primarily in acquiring, developing, exploiting and producing oil and gas properties. As of March 31, 2012, the Company’s assets and operations are concentrated primarily in southern Arkansas and in the Wattenberg field and North Park Basin in the Rocky Mountains.

 

2. BASIS OF PRESENTATION:

 

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). The quarterly financial statements included herein do not necessarily include all of the disclosures as may be required under generally accepted accounting principles.  The readers of these quarterly financial statements should also read the audited consolidated financial statements and related notes of BCEI that were included in BCEI’s Annual Report on Form 10-K filed with the SEC on March 22, 2012.  These consolidated financial statements include all of the

 

5

 

adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and results of operations.  All such adjustments are of a normal recurring nature only.  The results of operations for the quarterly periods are not necessarily indicative of the results to be expected for the full fiscal year.

 

Principles of Consolidation—The consolidated balance sheet includes the accounts of the Company and its wholly owned subsidiaries, Bonanza Creek Energy Operating Company, LLC, Bonanza Creek Energy Resources, LLC, HEC, Bonanza Creek Energy Upstream LLC, Bonanza Creek Energy Midstream, LLC and Liberty Energy Company, LLC.  All significant intercompany accounts and transactions have been eliminated.

 

Oil and Gas Producing Activities—The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells will be capitalized at cost when incurred, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs will be charged to expense. The costs of development wells will be capitalized whether productive or nonproductive. Costs incurred to maintain wells and related equipment and lease and well operating costs are charged to expense as incurred. Gains and losses arising from sales of properties will be included in income. However, sales that do not significantly affect a field’s unit-of-production depletion rate will be accounted for as normal retirements with no gain or loss recognized. Geological and geophysical costs of exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred.

 

Depletion, depreciation and amortization (“DD&A”) of capitalized costs of proved oil and gas properties are provided for on a field-by-field basis using the units of production method based upon proved reserves. The computation of DD&A takes into consideration the anticipated proceeds from equipment salvage and the Company’s expected cost to abandon its well interests.

 

The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows to the assets’ net book value. If the net capitalized costs exceed future net cash flows, then the cost of the property will be written down to “fair value.” Fair value for oil and natural gas properties is generally determined based on discounted future net cash flows.

 

3. RECENT ACCOUNTING PRONOUNCEMENTS:

 

In December 2011, the FASB issued Accounting Standards Update No. 2011-11, Balance Sheet: Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). The objective of ASU 2011-11 is to require an entity to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. ASU 2011-11 is effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively. The adoption of this standard is not expected to have an impact on the Company’s consolidated financial statements.

 

In May 2011, the FASB issued Accounting Standards Update No. 2011-04, Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”), which provides amendments to FASB ASC Topic 820, Fair Value Measurement.  The objective of ASU 2011-04 is to create common fair value measurement and disclosure requirements between GAAP and International Financial Reporting Standards (“IFRS”).  The amendments clarify existing fair value measurement and disclosure requirements and make changes to particular principles or requirements for measuring or disclosing information about fair value measurements.  These amendments are not expected to have a significant impact on companies applying GAAP.  ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011.  The adoption of this standard did not have an impact on the Company’s consolidated financial statements other than additional disclosures.

 

4. ACCOUNTS PAYABLE AND ACCRUED EXPENSES:

 

Accounts payable and accrued expenses contain the following:

 

		2012			2011
Drilling and completion costs		$	40,536,737		$	14,153,449
Accounts payable trade		1,999,942			4,976,979
Ad valorem taxes		999,932			1,781,021
Accrued general and administrative cost		2,586,461			1,713,708
Accrued initial public offering expenses		—			1,258,791
Lease operating expense		2,721,900			2,128,470
Accrued reclamation cost		400,000			400,000
Accrued interest		47,786			17,965
Accrued oil and gas hedging		654,340			353,897
Production taxes and other		1,609,809			284,046
		$	51,556,907		$	27,068,326

 

5. SENIOR SECURED REVOLVING CREDIT FACILITY:

 

Senior Secured Revolving Credit Facility—On March 29, 2011, the Company entered into a senior secured revolving Credit Agreement, (the “Revolver”), with a syndication of banks including BNP Paribas as the administrative agent and issuing lender, which provides for borrowings of up to $300 million. The Revolver provides for interest rates plus an applicable margin to be determined based on the London Interbank Offered Rate (LIBOR) or a bank base rate (“Base Rate”), at the Company’s election. LIBOR borrowings bear interest at LIBOR plus 1.75% to 2.75% depending on the utilization level, and the Base Rate borrowings bear interest at the “Bank Prime Rate,” as defined plus .75% to 1.75%.

 

The Revolver had a $220 million borrowing base as of March 31, 2012 and is subject to semi-annual re-determinations in April and October of each year. The Revolver provides for commitment fees ranging from 0.375% to 0.50%, depending on utilization, and restricts, among other items, the payment of dividends, certain additional indebtedness, sale of assets, loans, and certain investments and mergers. The Revolver also contains certain financial covenants, which require the maintenance of a minimum current ratio and a minimum debt coverage ratio, as defined. The Company was in compliance with these covenants as of March 31, 2012. The Revolver is collateralized by substantially all the Company’s assets and matures on September 15, 2016.

 

6. COMMITMENTS AND CONTINGENT LIABILITIES:

 

Office Leases—The Company rents office facilities under various noncancelable operating lease agreements.  The Company’s noncancelable operating lease agreements result in total future minimum noncancelable lease payments are presented below.  The Company also has principal payment requirements for its line of credit which is also presented below:

 

		Office Leases			Line of Credit			Total
2012		$	458,056		$	—		$	458,056
2013		744,242			—			744,242
2014		763,847			—			763,847
2015		785,424			—			785,424
2016 and thereafter		1,562,913			21,600,000			23,162,913
		$	4,314,482		$	21,600,000		$	25,914,482

 

6

 

Environmental—The Company is engaged in oil and gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures as they relate to the drilling of oil and gas wells and the operations. Relative to the Company’s acquisition of existing or previously drilled well bores, the Company may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean up or restoration, the liability to cure such a violation could fall upon the Company. Management believes its properties are operated in conformity with local, state and federal regulations. No claim has been made, nor is the Company aware of any uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration or the violation of any rules or regulations.

 

Legal Proceedings—The Company may from time to time be involved in various other legal actions arising in the normal course of business. During the second quarter of 2011, our Board of Directors formed a Special Litigation Committee comprised of three non-executive directors to investigate the merits of a demand for arbitration against our current President and Chief Executive Officer from the former Chairman of BCEC related to the management of BCOC and BCEC primarily during the 2005-2006 time period. These demands do not allege any wrongdoing by or claims against the Company. The Special Litigation Committee retained outside independent advisors to conduct the investigation and concluded that the allegations lack merit.

 

7. FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION:

 

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

 

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

 

ASC 820 requires financial assets and liabilities to be classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

 

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2012 by level within the fair value hierarchy:

 

		Fair Value Measurements Using
		Level 1			Level 2			Level 3
Commodity derivative assets		$	—		$	1,101,912		$	120,175
Commodity derivative liabilities		$	—		$	6,775,345		$	3,702,504

 

7

 

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2011 by level within the fair value hierarchy:

 

		Fair Value Measurements Using
		Level 1			Level 2			Level 3
Commodity derivative assets		$	—		$	1,094,055		$	881,822
Commodity derivative liabilities		$	—		$	6,740,213		$	1,115,595

 

Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.  All valuations were compared against counterparty statements to verify the reasonableness of the estimate.  The Company’s commodity swaps are validated by observable transactions for the same or similar commodity options using the NYMEX futures index, and are designated as Level 2 within the valuation hierarchy. The Company’s collars, which are designated as Level 3 within the valuation hierarchy, are not validated by observable transactions with respect to volatility. The counterparties in all of the commodity derivative financial instruments are lenders on the Company’s senior secured revolving credit facility.

 

The following table reflects the activity for the commodity derivatives measured at fair value using Level 3 inputs during the period from January 1, 2012 through March 31, 2012:

 

		Derivative Asset			Derivative Liability
Beginning net asset (liability) balance		$	881,822		$	1,115,595
Net increase in fair value		(761,647		)	2,812,269
Net realized loss on settlement		—			(225,360		)
Transfers in (out) of Level 3		—			—
Ending net asset (liability) balance		$	120,175		$	3,702,504

 

As of March 31, 2012, the Company’s derivative commodity contracts:

 

Contract Term		Notional Volume		Average Floor			Average Ceiling			Average Fixed Price
April 1 - December 31, 2012		67,956 Bbl./Month		$	90.00		$	106.45		—
January 1 - April 30, 2013		34,218 Bbl./Month		$	92.10		$	108.91		—
April 1 - December 31, 2012		9,644 Bbl./Month		—			—			$	63.03
January 1 - October 31, 2013		7,542 Bbl./Month		—			—			$	61.50
April 1 - December 31, 2012		16,729 MMBTU/Month		—			—			$	6.75
January 1 - October 31, 2013		15,481 MMBTU/Month		—			—			$	6.40

 

The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of March 31, 2012:

 

Derivatives		Balance Sheet Location		Fair Value
Asset
Commodity derivatives		Current derivative assets		$	885,490
Commodity derivatives		Long-term derivative assets		336,597
Liability
Commodity derivatives		Current derivative liability		(7,355,076		)
Commodity derivatives		Long-term derivative liability		(3,122,773		)
Total				$	(9,255,762	)

 

8

 

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

 

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

 

8. STOCKHOLDERS’ EQUITY:

 

Management Incentive Plan—On December 23, 2010, the Company established the Management Incentive Plan (the “Plan” or “MIP”) for the benefit of certain employees, officers and other individuals performing services for the Company. 10,000 shares of Class B common stock were available under the Plan and these shares were converted into 437,787 shares of restricted common stock upon completion of our initial public offering. The conversion rate was determined based on a formula factoring in the rate of return to the common stockholders. The 437,787 shares of common stock that were granted to employees were valued at $17.00 per share on the grant date and vest over a three year period. Non-cash compensation expense of approximately $618,000 was recorded during the quarter ended March 31, 2012 and there was approximately $6,702,000 of unrecognized compensation costs related to the unvested restricted common stock granted under the plan. That cost is expected to be recognized over a period of 2.7 years.

 

BCEC Management Incentive Plan—As of March 31, 2012, 73,197 shares of BCEI common stock remain held in trust and designated for holders of BCEC’s Class B units. When and if such shares are issued, they will be valued based on the market price of the Company’s common stock on the grant date.

 

9. 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.

 

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

 

The Company follows the provisions of FASB ASC 740, Accounting for Uncertainty in Income Taxes. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. The Company

 

9

 

files income tax returns in the U.S. federal jurisdiction and various states. The Company has not taken any uncertain tax positions.

 

10. SUBSEQUENT EVENTS:

 

Effective as of April 6, 2012, BNP Paribas was replaced by KeyBank National Association as administrative agent and issuing lender under our credit facility. The Company entered in to an amendment to its credit facility effective as of May 8, 2012.  The commitments under the credit facility were increased to $600 million and the borrowing base was increased to $245 million.

 

Recently, our Compensation Committee recommended, and our board of directors approved, the issuance of 540,000 shares of restricted common stock under our 2011 Long Term Incentive Plan to officers and certain employees.  These shares will be granted during June of 2012 after the expiration of the lock-up agreement contained in the underwriting agreement we entered into with the underwriters of our initial public offering.  For accounting purposes, these shares will be valued based on the closing price of our common stock on the grant date.  These shares will vest annually in one-third increments over approximately 2.7 years and will be fully vested in February of 2015.

 

10

 

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, 2011 (the “2011 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q (this “Report”).

 

This Report contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. These forward-looking statements may include projections and estimates concerning our capital expenditures, our liquidity and capital resources, our estimated revenues and losses, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, our business strategy and other statements concerning our operations, economic performance and financial condition. When used in this Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. The actual results 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.

 

Forward-looking statements may include statements about:

 

·                  our ability to replace oil and natural gas reserves;

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

·                  our financial position;

·                  our cash flow and liquidity;

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

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

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

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

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

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

·                  environmental risks;

·                  drilling and operating risks;

·                  exploration and development risks;

·                  competition in the oil and natural gas industry;

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

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

·                  access to adequate gathering systems and pipeline take-away capacity to execute 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 associated with perfecting title for mineral rights in some of our properties;

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

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

 

All forward-looking statements speak only as of the date of this Report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations below and under “Item 1A. Risk Factors” in our 2011 Annual Report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

Overview

 

Bonanza Creek Energy, Inc. (“BCEI” or, together with our consolidated subsidiaries, the “Company,” “we,” “us,” or “our”) is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States.  Our assets and operations are concentrated primarily in southern Arkansas (Mid-Continent region) and the Wattenberg Field and North Park Basins in Colorado (Rocky Mountain region).  In addition, we own and operate oil producing assets in the San Joaquin Basin (California region).  Our management team has extensive experience acquiring and operating oil and gas properties, which we believe will contribute to the development of our sizable inventory of projects, including those targeting the oily Cotton Valley sands in our Mid-Continent region and the Niobrara oil shale formation in our Rocky Mountain region.  We operate approximately 99.5% and hold an average working interest of approximately 80.7% of our proved reserves, providing us with significant control over the rate of development of our long-lived, low-cost asset base.

 

As demonstrated by our $165.5 million capital program in 2011 and our $250 million capital program for 2012, we are increasingly focused on exploiting our inventory of high return locations.  We continue to seek acquisitions that will complement our existing core properties.

 

11

 

Our revenue, profitability and future growth rate depend on factors beyond our control, such as economic, political and regulatory developments.  Oil and gas prices historically have been volatile and may fluctuate widely in the future.  We attempt to protect our capital and operational plans by judiciously hedging our sales of oil and natural gas.

 

First Quarter 2012 Highlights:

 

For the first quarter 2012,

 

·      Total production was 646 MBoe (7,100 Boe/d average daily production), a 96% increase over the first quarter 2011;

·      Total revenue was $49.5 million, a 123% increase over the first quarter 2011; and

·      Net income was $8.5 million, or $0.22 per diluted share.

 

Results of Operations

 

Revenues

 

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

 

		Three Months Ended March 31,
		2012			2011			Change			Percent Change
		(In thousands, except percentages)
Revenues:
Crude oil sales		$	41,836		$	16,576		$	25,260		152	%
Natural gas sales		3,273			2,926			347			12	%
Natural gas liquids sales		4,408			2,690			1,718			64	%
CO2 sales		25			21			4			19	%
Product revenues		$	49,542		$	22,213		$	27,329		123	%

 

		Three Months Ended March 31,
		2012		2011		Change		Percent Change
Sales volumes:
Crude oil (MBbls)		419.6		187.1		232.5		124	%
Natural gas (MMcf)		946.0		578.5		367.5		64	%
Natural gas liquids (MBbls)		68.8		46.3		22.5		49	%
Crude oil equivalent (MBoe)(1)		646.1		329.8		316.3		96	%

 

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

 

		Three Months Ended March 31,
		2012			2011			Change			Percent Change
Average Sales Prices (before hedging)(1):
Crude oil (per Bbl)		$	99.71		$	88.61		$	11.10		13	%
Natural gas (per Mcf)		3.46			5.06			(1.60		)	(32	)%
Natural gas liquids (per Bbl)		64.04			58.15			5.89			10	%
Crude oil equivalent (per Boe)(2)		76.64			67.30			9.34			14	%

 

		Three Months Ended March 31,
		2012			2011			Change			Percent Change
Average Sales Prices (after hedging)(1):
Crude oil (per Bbl)		$	96.33		$	83.57		$	12.76		15	%
Natural gas (per Mcf)		5.34			5.35			(0.01		)	—	%
Natural gas liquids (per Bbl)		64.04			58.15			5.89			10	%
Crude oil equivalent (per Boe)(2)		74.77			64.95			9.82			15	%

 

(1)  Although we do not designate our derivatives as cash flow hedges for financial statement purposes, the derivatives do economically hedge the price we receive for crude oil and natural gas.

 

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

 

Revenues increased by 123%, to $49.5 million for the three months ended March 31, 2012 compared to $22.2 million

 

12

 

for the three months ended March 31, 2011.  Oil, natural gas, and natural gas liquids production increased 124%, 64%, and 49%, respectively, during the three months ended March 31, 2012, as compared to the three months ended March 31, 2011.  During the period from March 31, 2011 through March 31, 2012, we drilled and completed 75 gross (72.5 net) wells in the Rockies and 45 gross (39.1 net) wells in Southern Arkansas. The increased volumes are a direct result of the $165.5 million expended for drilling and completion during the year ended December 31, 2011, and the $60.9 million expended during the three months ended March 31, 2012.  Oil prices increased from an average of $88.61 in 2011 to a per barrel rate of $99.71 in the comparable three month period that ended March 31, 2012.  The combination of increased oil volumes and prices accounted for $25.3 million of the total $27.3 million increase in revenues for the Company for the three month period ended March 31, 2012 compared to the same period in 2011.  Natural gas volumes increased by 64% in 2012, but were offset by a sales price decline of 32% from $5.06 per Mcf to $3.46 per Mcf for these three month periods.  Our natural gas sold in the Wattenberg field is sold without processing and sells at a premium due to its very high BTU content.  Our production of oil, natural gas liquids, and natural gas for the three months ended March 31, 2012 was approximately 65%, 10% and 25%, respectively.

 

Operating Expenses

 

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

 

		2012			2011			Change			Percent Change
		(In thousands, except percentages)
Expenses:
Lease operating		$	7,775		$	4,614		$	3,161		69	%
Severance and ad valorem taxes		3,691			1,053			2,638			250	%
General and administrative		5,965			2,239			3,726			166	%
Depreciation, depletion and amortization		11,828			6,387			5,441			85	%
Exploration		1,201			525			676			129	%
Operating expenses		$	30,460		$	14,818		$	15,642		106	%

 

		Three Months Ended March 31,
		2012			2011			Change			Percent Change
Selected Costs ($ per Boe):
Lease operating		$	12.03		$	13.99		$	(1.96	)	(14	)%
Severance and ad valorem taxes		5.71			3.19			2.52			79	%
General and administrative		9.23			6.79			2.44			36	%
Depreciation, depletion and amortization		18.31			19.37			(1.06		)	(5	)%
Exploration		1.86			1.59			0.27			17	%
Operating expenses		$	47.14		$	44.93		$	2.21		5	%

 

Lease Operating Expense.  Our lease operating expenses increased $3.2 million, or 69%, to $7.8 million for the three months ended March 31, 2012 from $4.6 million for the three months ended March 31, 2011 and decreased on an equivalent basis from $13.99 per Boe to $12.03 per Boe.  The increase in lease operating expense was related to increased production volumes attributable to our drilling program and the operation of an additional gas plant that was constructed during 2011, but not operational during the three months ended March 31, 2011.  Gas plant operating expense, which is a component of lease operating expense, increased $0.9 million, or 90%, to $1.9 million for the three month period ended March 31, 2012 from $1.0 million for the three month period ended March 31, 2011.  As such, the period-over-period gas plant operating expense roughly doubled as two gas plants were operated during the three months ended March 31, 2012 compared to one gas plant that was operated during the three months ended March 31, 2011.  During the three months ended March 31, 2012, well servicing, equipment rental, pumping and gauging, and other expenses were $0.9 million, $0.2 million, $0.2 million and $0.2 million higher, respectively, than the three months ended March 31, 2011.  The decrease in lease operating expense on an equivalent basis was primarily related to the lower per unit operating costs of the wells drilled during the period from March 31, 2011 through March 31, 2012.

 

Severance and ad valorem taxes.  Our severance and ad valorem taxes increased $2.6 million, or 250%, to $3.7 million for the three months ended March 31, 2012 from $1.0 million for the three months ended March 31, 2011.  The increase was primarily related to a 123% increase in production volumes and a 14% increase in realized prices per Boe during the three months ended March 31, 2012 as compared to the three months ended March 31, 2011.  The increase in severance and ad valorem taxes on a Boe basis for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011 was primarily related to higher ad valorem and severance taxes of $2.0 million and estimated severance tax payments to the state of Colorado in the amount of $0.5 million.

 

13

 

Exploration costs.  Our exploration expense increased $0.7 million, or 129%, to $1.2 million in the three months ended March 31, 2012 from $0.5 million in the three months ended March 31, 2011.  During the three months ended March 31, 2012, a seismic acquisition project was conducted in the North Park Basin of Colorado.  The North Park seismic data will assist the scientific staff in identifying the appropriate drill locations and plans for the development of our North Park Basin acreage.  During the three months ended March 31, 2011, we acquired 7,700 acres of 3-D seismic data on the eastern edge of the Wattenberg field in Weld County Colorado to help evaluate our Niobrara oil shale acreage.

 

Depletion, depreciation and amortization.  Our depletion, depreciation and amortization expense increased $5.4 million, or 85%, to $11.8 million for the three months ended March 31, 2012 from $6.4 million for the three months ended March 31, 2011.  This increase was the result of a 96% increase in production period over period.  Our depreciation, depletion and amortization expense per Boe produced decreased $1.06, or 5% to $18.31 for the three months ended March 31, 2012 as compared to $19.37 for the three months ended March 31, 2011.  This reduction to depreciation, depletion and amortization expense per Boe resulted from accretive reserve additions from the new wells drilled which more than offset the corresponding cost additions to the depletion base for these wells.

 

General and administrative. Our general and administrative expense increased $3.7 million, or 166%, to $6.0 million for the three months ended March 31, 2012 from $2.2 million for the period ended March 31, 2011. During the three months ended March 31, 2012, wages, benefits and employee placement fees were $2.4 million higher than the three month period ended March 31, 2011 due to our headcount increasing by approximately 50 employees, or 74% period over period, as the result of our accelerated drilling program and the addition of accounting, legal and IT positions that were previously outsourced. During the three months ended March 31, 2012, accounting fees were $0.4 million higher due to a one-time payment that was made to our outsource accounting provider to terminate our agreement with them. Also during the three months ended March 31, 2012, legal and professional fees were $0.2 million higher, franchise taxes were $0.2 million higher and non-cash stock compensation charges for officers and certain employees were $0.7 million higher than the three month period ended March 31, 2011. The majority of the increased general and administrative expense is due to hiring a large number of personnel to support our growth and the regulatory compliance obligations of a newly public company.

 

Interest expense.  Our interest expense decreased $0.1 million, or 27%, to $0.6 million for the three months ended March 31, 2012 from $0.7 million for the three months ended March 31, 2011.  The decrease resulted from a decrease in the average debt outstanding for the three months ended March 31, 2012 compared to the three months ended March 31, 2011.  Average debt outstanding for the three months ended March 31, 2012 was $15 million as compared to $61.4 million for the three month ended March 31, 2011.  The decrease in cash interest expense was offset by amortization of debt issue costs which increased $0.1 million to $0.3 million in the three months ended March 31, 2012 from $0.2 million in the first three months of 2011.

 

Realized loss on settled commodity derivatives.  Realized losses on oil and gas hedging activities increased by $0.4 million from a loss of $0.8 million for the three months ended March 31, 2011 to a loss of $1.2 million for the three months ended March 31, 2012.  The increase in the realized loss period over period was primarily related to commodity prices that were 14% higher during the three month period ended March 31, 2012.

 

Income tax expense.  Our estimate for federal and state income taxes for the three months ended March 31, 2012 was $5.4 million as compared to $0.2 million for the three months ended March 31, 2011.  We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation.  All income taxes for the periods ended March 31, 2012 and 2011 were deferred.  During the third quarter of 2011, the estimated effective tax rate was revised to reflect significant capital expenditures in Arkansas and the effective tax rate increased from 36.87% to 38%. Our effective tax rates differ from the U.S. statutory income tax rate primarily due to the effects of state income taxes.

 

Liquidity and Capital Resources

 

Our primary source of liquidity to date has been proceeds from our initial public offering, borrowings under our revolving credit facility and cash flows from operations.  Our primary use of capital has been the development and exploitation of our oil and gas properties.  We continually monitor potential capital sources in order to adequately plan for the growth of the Company and our planned capital expenditures and liquidity requirements.  Our future success in building and growing the Company’s reserves and production is significantly dependent upon management’s ability to access outside sources of capital.

 

On December 15, 2011, the Company sold 10,000,000 shares of our common stock in our initial public offering at $17.00 per share, less $1.105 per share for underwriting discounts and commissions.  Other expenses related to the issuance and distribution of these shares were approximately $3 million.

 

On March 29, 2011, we entered into a $300 million senior secured revolving credit facility to provide us with additional liquidity and flexibility for capital expenditures.  On November 23, 2011, our borrowing base under the credit facility was increased to $220 million. The size of our borrowing base is at the discretion of the lenders and is dependent upon a number of factors, including commodity prices and oil and gas reserve levels.  As of March 31, 2012, we had $21.6 million

 

14

 

outstanding and $198.4 million of borrowing capacity available under our credit facility.

 

On April 6, 2012, the administrative agent under our credit facility was changed to KeyBank, National Association.  On May 8, 2012, we entered into an amendment with the lenders under our credit facility to, among other things, (i) increase our credit facility to $600 million and borrowing base to $245 million, and (ii) make changes in the covenant applicable to hedging to allow greater flexibility for management to implement comprehensive hedging plans to adequately protect the Company’s operations and capital budgets.

 

We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas.

 

We are of the opinion that we have adequate liquidity to manage our capital and business plans for the next 12 months and the foreseeable future.  In addition, we believe that the combination of our cash flow from operating activities, access to debt and capital markets and our current liquidity level will allow us the flexibility to modify our future capital expenditure programs and comply with all of our debt covenants, and meet all of our obligations that may arise from our ongoing operations.

 

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

 

		Three Months Ended March 31,
		2012			2011
		(In thousands)
Net cash provided by operating activities		$	17,685		$	10,186
Net cash provided by (used in) investing activities		(34,740		)	(16,531		)
Net cash provided by financing activities		14,965			7,113
Cash and cash equivalents		—			768
Acquisitions of oil and gas properties		294			46
Exploration and development of oil and gas properties and investment in gas processing facility		33,711			17,407

 

Cash flows provided by operating activities

 

Cash flows derived from operating activities depend on many factors including the price for oil and gas, our success in exploiting and exploring our oil and gas properties which ultimately leads to the volumes produced.  Costs and the containment thereof to produce the oil and gas, and the severance and ad valorem taxes associated with the ownership and production of oil and gas wells have a significant impact on the profitability and cash flow from oil and gas properties.

 

Net cash provided by operating activities was $17.7 million for the three months ended March 31, 2012, compared to $10.2 million provided by operating activities for the three months ended March 31, 2011.  The increase in operating activities results primarily from an increase in revenues, increased production, and increased commodity prices offset by cash utilized in connection with changes in working capital when comparing periods.  Cash utilized by changes in working capital for the three months ended March 31, 2012 was $12.4 million compared to $2.4 million that was utilized by changes in working capital for the comparable period during 2011.  Decreases in working capital of $12.4 million for the three months ended March 31, 2012 is comprised of increases in accounts receivable of $14.5 million offset by an increase in accounts payable and accrued liabilities (exclusive of capital accruals) of $2.2 million.  Decreases in working capital of $2.4 million for the three month period ended March 31, 2011 is comprised of increases in accounts receivable of $0.5 million, increases in prepaid expense and other current assets of $0.4 million, and decreases in accounts payable and accrued liabilities (exclusive of capital accruals) of $1.5 million.

 

Cash flows used in investing activities

 

Expenditures for development of oil and natural gas properties and natural gas plants are the primary use of our capital resources.  Net cash used in investing activities for the three months ended March 31, 2012 was $34.7 million, compared to $16.5 million used in investing activities for the three months ended March 31, 2011.  For the three months ended March 31, 2012, cash used for the development of oil and natural gas properties was $33.7 million including $6.3 million for a natural gas plant.  In the Wattenberg field during the three months ended March 31, 2012, we drilled and completed 5 gross (4.1 net) horizontal wells and had 3 gross (2.9 net) more horizontal wells in various stages of drilling and completion in the Niobrara.  We also drilled 22 gross (20.3 net) vertical wells.  In Southern Arkansas, we drilled and completed 7 gross (5.6 net) wells and recompleted 31 gross (25.5 net) wells to add zones in existing wells.

 

Cash provided by financing activities

 

Net cash flow provided by financing activities for the three months ended March 31, 2012 was $15.0 million related to

 

15

 

net borrowings on our line of credit.  Net cash provided by financing activities for the three months ended March 31, 2011 was $7.1 million related to net borrowings on our line of credit in the amount of $8.1 million offset by deferred financing costs of $1.0 million.

 

Interest under our credit facility is generally determined by reference to either, at our option, (i) the London interbank offered rate, or LIBOR, for an elected interest period, plus an applicable margin between 1.75% to 2.75% depending on utilization level, or (ii) an alternate base rate (the highest of the administrative agent’s prime rate, the federal funds effective rate plus 0.5% or three-month LIBOR plus 1.00%), plus an applicable margin between 0.75% and 1.75%. Our credit facility provides for commitment fees of 0.375% to 0.50%, depending on utilization, and restricts, among other items, the payment of dividends, certain additional indebtedness, sale of assets, loans, certain investments and acquisitions.

 

New Accounting Pronouncements

 

For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, please refer to the Adopted and Recently Issued Accounting Pronouncements footnote in the Notes to the Consolidated Financial Statements.

 

Critical Accounting Policies and Estimates

 

Information regarding critical accounting policies and estimates is contained in Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2011.

 

Inflation

 

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the three month periods ended March 31, 2012 and 2011.  Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

 

Off-balance sheet arrangements

 

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

 

Item 3.    Quantitative and Qualitative Disclosures About Market Risk.

 

Oil and Natural Gas Prices.  Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control.  Factors influencing oil and natural gas prices include the level of global demand for oil, the global supply of oil and natural gas, the establishment of and compliance with production quotas by oil exporting countries, weather conditions which determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions.  It is impossible to predict future oil and natural gas prices with any degree of certainty.  Sustained weakness in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of oil and natural gas reserves that we can produce economically.  Any reduction in our oil and natural gas reserves, including reductions due to price fluctuations, can have an adverse affect 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.  If oil prices decline by $10.00 per Bbl, then our PV-10 as of December 31, 2011 would have been lower by approximately $129.4 million.

 

Our primary commodity risk management objective is to reduce volatility in our cash flows.  Management makes recommendations on hedging that are approved by the board of directors before implementation.  We enter into hedges for oil and natural gas using NYMEX futures or over-the-counter derivative financial instruments with only certain well-capitalized counterparties who have been approved by our board of directors.

 

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

 

16

 

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

 

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

 

The following table provides a summary of derivative contracts as of March 31, 2012.

 

Settlement Period		Derivative Instrument		Total Notional Amount (Bbl/Mmbtu)		Average Floor Price			Average Ceiling Price			Fair Market Value of Asset (Liability)
												(In thousands)
Oil
2012		Collar		611,604		$	90.00		$	106.45		$	(2,700,857	)
		Swap		86,798		63.03			63.03			(3,595,495		)
2013		Collar		410,616		92.10			108.91			(881,472		)
		Swap		75,417		61.50			61.50			(3,179,849		)
Gas
2012		Swap		150,559		6.75			6.75			639,645
2013		Swap		154,806		6.40			6.40			462,266
												$	(9,255,762	)

 

Item 4.    Controls and Procedures.

 

Evaluation of Disclosure Controls and Procedures

 

Our management, including our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of March 31, 2012.  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 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, 2012, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

 

Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

 

Changes in Internal Control over Financial Reporting

 

There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended March 31, 2012 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

PART II—OTHER INFORMATION

 

Item 1.    Legal Proceedings.

 

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

 

17

 

In June 2011, Frank H. Bennett, a co-manager of Bonanza Creek Oil Company, LLC (“BCOC”), Bonanza Creek Energy, LLC’s (“BCEC”) predecessor, and former chairman of BCEC, made a demand against Michael R. Starzer, our President and Chief Executive Officer, focusing on Mr. Starzer’s handling of the operation, accounting and finances of BCOC and BCEC primarily during the 2005-2006 time period. Mr. Bennett’s demands do not allege any wrongdoing by or claims against Bonanza Creek Energy, Inc. This matter was sent to arbitration in July 2011.

 

In July 2011, our board of directors formed a Special Litigation Committee comprised of three non-executive directors to conduct an investigation of the allegations. The Special Litigation Committee retained outside independent advisors and conducted an in-depth investigation. The Special Litigation Committee concluded that neither it nor its legal or financial advisors had found any evidence to support any of Mr. Bennett’s allegations. Our board of directors concluded that the allegations against Mr. Starzer are unsubstantiated and lack merit. However, there can be no assurance as to the ultimate outcome of the arbitration proceedings. The parties are currently conducting discovery. The arbitration hearing is scheduled to commence in July 2012.

 

See Part I, Item 1, Note 6 to our unaudited condensed consolidated financial statements entitled “Commitment and Contingent Liabilities,” which is incorporated herein by reference.

 

Item 1A. Risk Factors.

 

Our business faces many risks.  Any of the risk factors discussed in this Report, Item 1A of our 2011 Annual Report or our other SEC filings could have a material impact on our business, financial position or results of operations.  Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation.  During the three months ended March 31, 2012, there has been no material change to such risk factors.

 

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

 

None.

 

Item 3.    Defaults Upon Senior Securities.

 

None.

 

Item 4.    Mine Safety Disclosures.

 

Not applicable.

 

Item 5.    Other Information.

 

None.

 

Item 6.    Exhibits.

 

Exhibit No.		Description of Exhibit
10.1		Resignation, Consent and Appointment Agreement and Amendment Agreement, dated of April 6, 2012, by and among BNP Paribas, in its capacity as Administrative Agent and Issuing Lender, and the other parties thereto
10.2		Amendment No. 3 & Agreement, dated as of May 8, 2012, to the Credit Agreement among Bonanza Creek Energy, Inc., KeyBank National Association, as Administrative Agent, and the lenders party thereto
31.1		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)
31.2		Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)
32.1		Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith)
32.2		Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith)
101		The following materials from the Bonanza Creek Energy, Inc. Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, formatted in XBRL (Extensible Business Reporting Language) include (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Stockholders’ Equity, (iv) the Condensed Consolidated Statements of Cash Flows and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text. The information in Exhibit 101 is “furnished” and not “filed”, as provided in Rule 402 of Regulation S-T.

 

18

 

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 10, 2012		By:	/s/ MICHAEL R. STARZER
			Michael R. Starzer
			President and Chief Executive Officer
			(principal executive officer)
			By:	/s/ JAMES R. CASPERSON
			James R. Casperson
			Executive Vice President and Chief Financial Officer
			(principal financial officer)

 

19