CIVITAS RESOURCES, INC. - Quarter Report: 2013 March (Form 10-Q)

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

 

 

For the quarterly period ended March 31, 2013

 

or

 

 

For the transition period from            to            

 

Commission File Number: 001-35371

 

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).  o Yes  x No

 

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. 40,263,316 shares of common stock were outstanding as of April 29, 2013.

 

 

 

PART I - FINANCIAL INFORMATION

 

Item 1.         Financial Statements.

 

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

 

(unaudited)

 

		March 31, 2013			December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	3,170,403		$	4,267,667
Accounts receivable:
Oil and gas sales		43,842,227			38,600,436
Joint interest and other		7,154,967			5,484,620
Prepaid expenses and other		2,950,855			3,031,815
Inventory of oilfield equipment		3,956,611			1,740,934
Derivative asset		696,195			2,178,064
Total current assets		61,771,258			55,303,536
OIL AND GAS PROPERTIES—using the successful efforts method of accounting:
Proved properties		841,450,815			811,000,239
Unproved properties		73,286,904			72,928,364
Wells in progress		104,331,607			75,031,806
		1,019,069,326			958,960,409
Less: accumulated depreciation, depletion and amortization		(111,949,634		)	(89,669,725		)
		907,119,692			869,290,684
NATURAL GAS PLANT		74,276,579			73,087,603
Less: accumulated depreciation		(4,016,914		)	(3,403,817		)
		70,259,665			69,683,786
PROPERTY AND EQUIPMENT		6,476,164			5,089,795
Less: accumulated depreciation		(1,245,821		)	(890,093		)
		5,230,343			4,199,702
OIL AND GAS PROPERTIES HELD FOR SALE LESS ACCUMULATED DEPRECIATION, DEPLETION, AND AMORTIZATION		572,079			582,388
LONG-TERM DERIVATIVE ASSET		534,993			—
OTHER ASSETS, net		3,262,256			3,429,711
TOTAL ASSETS		$	1,048,750,286		$	1,002,489,807
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued expenses		$	62,292,672		$	72,850,272
Oil and gas revenue distribution payable		11,503,132			12,552,655
Contractual obligation for land acquisition		11,999,877			11,999,877
Derivative liability		8,145,564			5,200,202
Total current liabilities		93,941,245			102,603,006
LONG-TERM LIABILITIES:
Bank revolving credit		191,500,000			158,000,000
Contractual obligation for land acquisition		33,461,957			33,271,631
Ad valorem taxes		12,259,384			11,179,370
Derivative liability		924,520			1,208,106
Deferred income taxes, net		117,424,350			110,376,606
Asset retirement obligations		7,995,594			7,333,584
TOTAL LIABILITIES		457,507,050			423,972,303
COMMITMENTS AND CONTINGENCIES (Notes 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, 40,269,003 and 40,115,536 issued and outstanding, respectively		40,269			40,116
Additional paid-in capital		520,895,119			519,425,356
Retained earnings		70,307,848			59,052,032
Total stockholders’ equity		591,243,236			578,517,504
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	1,048,750,286		$	1,002,489,807

 

See accompanying notes to these consolidated financial statements.

 

2

 

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF OPERATIONS

 

(unaudited)

 

		Three Months Ended March 31,
		2013			2012
NET REVENUES
Oil and gas sales		$	78,307,013		$	47,830,431
OPERATING EXPENSES:
Lease operating		11,130,685			7,107,331
Severance and ad valorem taxes		4,812,754			3,595,809
Exploration		562,312			1,190,123
Depreciation, depletion and amortization		23,363,065			11,001,043
General and administrative (including $4,378,287 and $670,564, respectively, of stock compensation)		13,166,062			5,964,718
Total operating expenses		53,034,878			28,859,024
INCOME FROM OPERATIONS		25,272,135			18,971,407
OTHER INCOME (EXPENSE):
Realized (loss) on settled commodity derivatives		(1,507,120		)	(1,211,139		)
Interest expense		(1,962,718		)	(561,516		)
Unrealized (loss) in fair value of commodity derivatives		(3,608,652		)	(3,375,831		)
Other income (loss)		136,933			(37,727		)
Total other (loss)		(6,941,557		)	(5,186,213		)
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES		18,330,578			13,785,194
Income tax expense		(7,058,146		)	(5,307,300		)
INCOME FROM CONTINUING OPERATIONS		$	11,272,432		$	8,477,894
DISCONTINUED OPERATIONS (Note 3)
(Loss) income from operations associated with oil and gas properties held for sale		(27,018		)	110,990
Income tax benefit (expense)		10,402			(42,731		)
(Loss) income associated with oil and gas properties held for sale		(16,616		)	68,259
NET INCOME		$	11,255,816		$	8,546,153
COMPREHENSIVE INCOME		$	11,255,816		$	8,546,153
BASIC AND DILUTED INCOME PER SHARE
Income from continuing operations		$	0.28		$	0.22
Income (loss) from discontinued operations		$	—		$	—
Net income per common share		$	0.28		$	0.22
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—BASIC AND DILUTED		40,084,811			39,477,584

 

See accompanying notes to these consolidated financial statements.

 

3

 

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(unaudited)

 

		Three Months Ended March 31,
		2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	11,255,816		$	8,546,153
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		23,467,406			11,827,980
Deferred income taxes		7,047,744			5,350,031
Stock-based compensation		4,378,287			670,564
Exploration		351,464			—
Amortization of deferred financing costs		218,691			288,494
Accretion of contractual obligation for land acquisition		190,326			—
Valuation decrease in commodity derivatives		3,608,652			3,375,831
Other		73,342			45,000
(Increase) decrease in operating assets:
Accounts receivable		(6,912,138		)	(14,542,748		)
Prepaid expenses and other assets		80,960			(106,250		)
(Decrease) increase in operating liabilities:
Accounts payable and accrued liabilities		(5,418,908		)	2,230,988
Settlement of asset retirement obligations		(49,163		)	(749		)
Net cash provided by operating activities		38,292,479			17,685,294
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of oil and gas properties		(934,054		)	(294,127		)
Exploration and development of oil and gas properties		(64,334,333		)	(27,464,392		)
Natural gas plant capital expenditures		(3,275,378		)	(6,246,577		)
Decrease (increase) in restricted cash		—			(139,375		)
Additions to property and equipment—non oil and gas		(1,386,369		)	(595,439		)
Net cash (used) in investing activities		(69,930,134		)	(34,739,910		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in bank revolving credit		33,500,000			15,000,000
Common stock returned for tax withholdings		(2,908,373		)	—
Deferred financing costs		(51,236		)	(35,058		)
Net cash provided by financing activities		30,540,391			14,964,942
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(1,097,264		)	(2,089,674		)
CASH AND CASH EQUIVALENTS:
Beginning of period		4,267,667			2,089,674
End of period		$	3,170,403		$	—
SUPPLEMENTAL CASH FLOW DISCLOSURE:
Cash paid for interest		$	1,469,356		$	243,201
Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition		$	(5,459,665	)	$	26,102,288

 

See accompanying notes to these consolidated financial statements.

 

4

 

Bonanza Creek Energy, Inc.

Notes to the Consolidated Financial Statements as of March 31, 2013 (unaudited)

 

1. ORGANIZATION AND BUSINESS:

 

Bonanza Creek Energy, Inc. (the “Company” or “BCEI”) is engaged primarily in acquiring, developing, exploiting and producing oil and gas properties. As of March 31, 2013, the Company’s assets and operations are concentrated primarily in the Wattenberg Field in the Rocky Mountains and in Southern Arkansas. The Company completed its initial public offering of common stock in December 2011 (the “IPO”) pursuant to which 10,000,000 shares of common stock were sold.

 

2. BASIS OF PRESENTATION:

 

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The quarterly financial statements included herein do not necessarily include all of the disclosures as may be required under generally accepted accounting principles. The readers of these quarterly financial statements should also read the audited consolidated financial statements and related notes of BCEI that were included in BCEI’s Annual Report on Form 10-K filed with the SEC on March 15, 2013. These consolidated financial statements include all of the adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and results of operations. All such adjustments are of a normal recurring nature only. The results of operations for the quarterly periods are not necessarily indicative of the results to be expected for the full fiscal year.

 

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

 

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

 

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

 

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

 

3. DISCONTINUED OPERATIONS:

 

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

 

		As of March 31, 2013			As of December 31, 2012
PROPERTY AND EQUIPMENT:
Oil and gas properties, successful efforts method:
Proved properties		$	1,721,265		$	1,721,265
Unproved properties		629			629
Wells in progress		100,936			39,245
Total property and equipment		1,822,830			1,761,139
Less accumulated depletion and depreciation		(1,250,751		)	(1,178,751		)
Net property and equipment		$	572,079		$	582,388

 

5

 

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

 

		Three Months Ended March 31,			Three Months Ended March 31,
		2013			2012
NET REVENUES:
Oil and gas sales		$	437,945		$	1,711,898
OPERATING EXPENSES:
Lease operating		303,271			667,743
Severance and ad valorem taxes		193			95,626
Exploration		57,158			10,602
Depreciation, depletion and amortization		104,341			826,937
TOTAL COSTS AND EXPENSES		464,963			1,600,908
INCOME (LOSS) FROM OPERATIONS ASSOCIATED WITH OIL AND GAS PROPERTIES HELD FOR SALE		$	(27,018	)	$	110,990

 

4. ACCOUNTS PAYABLE AND ACCRUED EXPENSES:

 

Accounts payable and accrued expenses contain the following:

 

		As of March 31, 2013			As of December 31, 2012
Drilling and completion costs		$	46,239,017		$	51,698,682
Accounts payable trade		407,591			10,049,131
Accrued general and administrative cost		5,142,425			5,078,059
Lease operating expense		4,047,200			2,824,300
Accrued reclamation cost		400,000			400,000
Accrued interest		303,839			219,494
Accrued oil and gas hedging		433,616			238,365
Production taxes and other		5,318,984			2,342,241
		$	62,292,672		$	72,850,272

 

5. SENIOR SECURED REVOLVING CREDIT FACILITY:

 

The Company’s senior secured revolving Credit Agreement (the “Revolver”), dated March 29, 2011, as amended, with a syndication of banks, including KeyBank National Association as the administrative agent and issuing lender, provides for borrowings of up to $600 million. The Revolver provides for interest rates plus an applicable margin to be determined based on the London Interbank Offered Rate (“LIBOR”) or a bank base rate (“Base Rate”), at the Company’s election. LIBOR borrowings bear interest at LIBOR plus 1.75% to 2.75% depending on the utilization level, and the Base Rate borrowings bear interest at the “Bank Prime Rate,” as defined plus .75% to 1.75%.

 

The borrowing base under the Revolver was $325 million as of March 31, 2013 (See Note 10 for a discussion of a new debt issuance subsequent to the end of the first quarter which reduced the borrowing base to $250 million). The borrowing base is redetermined semiannually by May 15 and November 15 and may be redetermined up to one additional time between such scheduled determinations upon request by the Company or lenders holding 66 and 2/3% of the aggregate commitments. A letter of credit that was issued to the Colorado State Board of Land Commissioners in connection with the Company’s lease of acreage in the Wattenberg Field reduces the borrowing base under the Revolver by approximately $48 million. 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

 

6

 

covenants as of March 31, 2013.  The Revolver is collateralized by substantially all the Company’s assets and matures on September 15, 2016. As of March 31, 2013, there was $191.5 million outstanding and a $48.0 million letter of credit issued under the Revolver, and the Company had $85.5 million available for future borrowings under the Revolver.

 

6. COMMITMENTS AND CONTINGENT LIABILITIES:

 

Contingent Liabilities—From time to time, the Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures.

 

Environmental—The Company is engaged in oil and gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures as they relate to the drilling of oil and gas wells and associated operations. Relative to the Company’s acquisition of existing or previously drilled well bores, the Company may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental cleanup or restoration, the liability to cure such a violation could fall upon the Company. Management believes its properties are operated in conformity with local, state and federal regulations. No claims have 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—From time to time, the Company is subject to legal proceedings and claims that arise in the ordinary course of business. Like other gas and oil producers and marketers, the Company’s operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges and solid and hazardous waste management activities. As of the date of this filing, there are no material pending or overtly threatened legal actions against the Company of which it is aware.

 

Commitments—The Company rents office facilities under various 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			Wattenberg Field Lease Acquisition			Line of Credit			Total
2013		1,058,711			11,999,877			—			13,058,588
2014		1,496,803			11,999,877			—			13,496,680
2015		1,539,865			11,999,877			—			13,539,742
2016		1,185,363			11,999,877			191,500,000			204,685,240
2017 and thereafter		1,391,894			—			—			1,391,894
		$	6,672,636		$	47,999,508		$	191,500,000		$	246,172,144

 

7. FAIR VALUE MEASUREMENTS AND ASSET RETIREMENT OBLIGATION:

 

The Company defines fair value under a framework for using fair value to measure assets and liabilities, and expands disclosures about fair value measurements. A hierarchy for inputs is used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.  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;

 

7

 

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 Company’s commodity swaps are valued using a market approach based on several factors, including observable transactions for the same or similar commodity options using the NYMEX futures index, and are designated a Level 2 within the valuation hierarchy. The Company’s collars, which are designated as Level 3 within the valuation hierarchy, are also valued using a market approach, but are not validated by observable transactions with respect to volatility. As of March 31, 2013, four of the five counterparties in the Company’s commodity derivative financial instruments are lenders on the Company’s Senior Secured Revolving Credit facility (Note 6).

 

The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2013 and December 31, 2012 by level within the fair value hierarchy:

 

		Fair Value Measurements Using
		Level 1			Level 2			Level 3
March 31, 2013
Commodity derivative assets		$	—		$	250,220		$	980,968
Commodity derivative liabilities		$	—		$	6,723,170		$	2,346,914

 

December 31, 2012
Commodity derivative assets		$	—		$	450,872		$	1,727,192
Commodity derivative liabilities		$	—		$	5,173,140		$	1,235,168

 

The following table reflects the activity for the commodity derivatives measured at fair value using Level 3 inputs during the period from January 1, 2013 through March 31, 2013:

 

		Derivative Asset			Derivative Liability
Beginning balance		$	1,727,192		$	1,235,168
Net (decrease) increase in fair value		(2,021,643		)	69,269
Net realized (gain) on settlement		—			430
New derivatives		1,275,419			1,042,047
Ending balance		$	980,968		$	2,346,914

 

As of March 31, 2013, the Company’s derivative commodity contracts are as follows:

 

Contract Term		Notional Volume		Average Floor			Average Ceiling			Average Fixed Price per Unit
April 1 - December 31, 2013		3,164 Bbl./Day		$	88.38		$	101.58		—
January 1 - December 31, 2014		3,589 Bbl./Day		$	86.72		$	95.53		—
April 1 - December 31, 2013		2,809 Bbl./Day		—			—			$	88.69
January 1 - December 31, 2014		625 Bbl./Day		—			—			$	90.80
April 1 - October 31, 2013		504 MMBTU/Day		—			—			$	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, 2013:

 

Derivatives		Balance Sheet Location		Fair Value
Asset
Commodity derivatives		Current derivative assets		$	696,195
Commodity derivatives		Long-term derivative assets		534,993
Liability
Commodity derivatives		Current derivative liability		(8,145,564		)
Commodity derivatives		Long-term derivative liability		(924,520		)
Total				$	(7,838,896	)

 

8

 

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

 

Proved Oil and Gas Properties—Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs exceed the sum of the undiscounted cash flows. The Company uses Level 3 inputs and the income valuation technique, which converts future amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates and price forecasts selected by the Company’s management. The calculation of the discount rate is a significant management estimate based on the best information available and estimated to be 10 percent for the three months ended March 31, 2013 and 2012. Management believes that the discount rate is representative of current market conditions and reflects the following factors: estimate of future cash payments, expectations of possible variations in the amount and/or timing of cash flows, the risk premium, and nonperformance risk. The price forecast is based on New York Mercantile Exchange (“NYMEX”) strip pricing, adjusted for basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates.

 

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 the IPO. The conversion rate was determined based on a formula factoring in the rate of return to the pre-IPO common stockholders. The 437,787 shares of common stock that were granted to employees were valued at $17.00 per share on the grant date and vest over a three year period. Non-cash compensation expense of approximately $569,000 was recorded during the three months ended March 31, 2013 and there was approximately $3,896,000 of unrecognized compensation costs related to the unvested restricted common stock granted under the MIP. That cost is expected to be recognized over a period of 1.75 years. The MIP has been terminated such that there will be no future grants thereunder.

 

BCEC Investment Trust— The BCEC Investment Trust was formed to hold shares of our common stock received by Bonanza Creek Energy Company, LLC, our predecessor, in connection with our December 23, 2010 corporate restructuring. On February 5, 2013, 13,825 previously issued shares of our common stock that were fully vested and held by the BCEC Investment Trust were distributed to former employees. While the shares had been issued in December 2010, for accounting purposes, the date of distribution to former employees was considered the grant date, and these shares were valued at the closing price of our common stock on the grant date which was $34.18 per share. On February 11, 2013, 59,372 previously issued shares of our common stock that were fully vested and held by the BCEC Investment Trust were distributed to certain current employees. While the shares had been issued in December 2010, for accounting purposes, the date of distribution to employees was considered the grant date, and these shares were valued at the closing price of our common stock on the grant date which was $34.89 per share. These distributions resulted in a stock-based compensation expense of $2,544,000 during the three months ended March 31, 2013.

 

2011 Long Term Incentive Plan. During 2012, the Company granted 703,246 shares of restricted common stock under its 2011 Long Term Incentive Plan (the “LTIP”) to officers and certain key employees. For accounting purposes, these shares are valued at the closing price of our common stock on the grant date. These shares will vest annually in one-third increments over three years. Stock-based compensation expense of $1,019,000 was recorded during the three months ended March 31, 2013 and there was $8,227,000 of unrecognized compensation costs related to the unvested restricted common stock granted under the LTIP. That cost is expected to be recognized over a period of 2.67 years.

 

On March 28, 2013, the Company granted 229,470 shares of restricted common stock under the LTIP to officers and certain key employees. For accounting purposes, these shares are valued at the closing price of our common stock on the grant date. These shares will vest annually in one-third increments over three years. Stock-based compensation expense of $24,000 was recorded during the period ended March 31, 2013 and there was $8,849,000 of unrecognized compensation costs as of March 31, 2013 related to the unvested restricted stock granted under the LTIP. That cost is expected to be recognized over a period of 3 years.

 

On March 28, 2013, the Company granted 34,354 Performance Stock Units (“PSUs”) under the LTIP to certain officers. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded and is determined based on the Company’s performance over a three-year measurement period. The performance criterion for the PSUs is based on a comparison of the Company’s Total Shareholder Return (“TSR”) for the measurement period

 

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compared with the TSRs of a group of peer companies for the measurement period. Expense associated with PSUs of is recognized as general and administrative expense over the vesting period.

 

The fair value of the PSUs was measured at the grant date with a stochastic process method using the Geometric Brownian Motion Model (“GBM Model”). A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company’s PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the three-year performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the GBM Model, is deemed an appropriate method by which to determine the fair value of the PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, dividend yield, and risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with a three year vesting period, as well as the volatilities and dividend yields for each of the Company’s peers. Stock-based compensation expense of $3,200 was recorded during the period ended March 31, 2013 and there was $1,057,000 of unrecognized compensation cost as of March 31, 2013 related to the unvested PSUs granted under the LTIP. That cost is expected to be recognized over a period of 2.76 years.

 

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. During the three month periods ended March 31, 2013 and 2012 the effective tax rate was 38.5%.

 

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

 

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 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:

 

On April 9, 2013, the Company sold $300,000,000 of 6.75% Senior Notes (the “Senior Notes”). Interest on the Senior Notes will accrue from April 9, 2013, and we will pay interest on April 15 and October 15 of each year, beginning on October 15, 2013. The Senior Notes will mature on April 15, 2021. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by our existing, and will be by our future, subsidiaries that incur or guarantee certain indebtedness, including indebtedness under our revolving credit facility. We may redeem the Senior Notes (i) at any time on or after April 15, 2017 at the redemption price equal to 100% together with accrued and unpaid interest, and (ii) prior to April 15, 2017 at the “make-whole” redemption prices described in the indenture together with accrued and unpaid interest. The net proceeds from the sale of the Senior Notes were approximately $293.2 million after deducting estimated expenses and underwriting discounts and commissions and the proceeds were used to repay all of the outstanding borrowings under our revolving credit facility, which was $191,500,000 as of April 9, 2013. The remaining proceeds will be used for general corporate purposes, which may include funding our drilling and development program and other capital expenditures. Concurrent with the closing of the Senior Notes sale, our borrowing base under our revolving credit facility was reduced from $325 million to $250 million. Pro forma for the sale of the Senior Notes and subsequent borrowing base reduction, our liquidity as of March 31, 2013 was $306.9 million. The pro forma liquidity of $306.9 million is comprised of the $250 million borrowing base, $293.2 million of net proceeds from the sale of the Senior Notes and the current cash position of $3.2 million. This amount is offset by the $48 million letter of credit that was issued to the Colorado State Board of Land Commissioners in connection with the Company’s lease of acreage in the Wattenberg Field and the $191.5 million outstanding on the revolver at March 31, 2013.

 

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

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2012 (the “2012 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q (this “Report”).

 

Executive Summary

 

Bonanza Creek Energy, Inc. (“BCEI” or, together with our consolidated subsidiaries, the “Company,” “we,” “us,” or “our”) is a Denver-based exploration and production company focused on the extraction of oil and associated liquids-rich natural gas in the United States. Our predecessors were founded in 1999 and we went public in December 2011. Our shares of common stock are listed for trading on the NYSE under the symbol “BCEI.”

 

Despite the uncertainty surrounding the global economy and continued volatility in commodity prices, we believe our portfolio positions us well moving forward. Our operations are focused in the Wattenberg Field in Colorado and the Cotton Valley sands of southern Arkansas. The low risk, oily and stable production profile of our Arkansas assets provides a strong cash flow base from which to develop the Niobrara and Codell formations in Colorado. Our corporate strategy is to create shareholder value by increasing production in our current assets, while opportunistically seeking strategic acquisitions in other high return basins across the United States where we can apply our core competencies of horizontal drilling and fracture stimulation. We maintain a high working interest in our properties.

 

First Quarter 2013 Financial and Operating Highlights

 

Our financial results for the quarter ended March 31, 2013 included:

 

·  Net income of $11.3 million (including approximately $11.3 million from continuing operations), as compared with $8.5 million (including approximately $8.5 million from continuing operations) for the first quarter of 2012;

 

·  Cash flows provided by operating activities of $38.3 million, as compared with $17.7 million in the first quarter of 2012;

 

·  Capital expenditures of $61.4 million, as compared with $60.9 million in the first quarter of 2012; and

 

·  Total liquidity of $88.7 million at March 31, 2013, consisting of a period-end cash balance plus funds available under our credit facility, as compared with $200.5 million at March 31, 2012.

 

Operational highlights for the first quarter of 2013 included the following:

 

·  Increased production by 76% to 1,107.6 MBoe in the first quarter of 2013 from 630.2 MBoe in the first quarter of 2012, with oil and NGL production representing 72% of total production; and

 

·  Decreased average production costs per Boe by 11% to $10.05 per Boe in 2013 from $11.28 per Boe in the first quarter of 2012, primarily as a result of our decision to transition from vertical wells to horizontal wells in the Wattenberg Field in July 2012.

 

Outlook for 2013

 

We continue to monitor the outlook for the global economy and numerous critical factors, including the United States federal budget deficit and long-term fiscal situation and the European debt crisis, and their potential impacts on global economic growth and commodity prices. Because the global economic outlook and commodity price environment are uncertain, we have planned a flexible capital spending program. We estimate our total capital expenditures for 2013 to be approximately $400 million, allocated approximately 80% to the Wattenberg Field and 20% to southern Arkansas. Actual capital expenditures are subject to a number of factors, including economic conditions and commodity prices, and the Company may reduce or augment the budget as appropriate. This capital investment is expected to produce 2013 average sales volumes of 14,500 to 16,000 Boe/d, while maintaining a strong oil and liquids profile.

 

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Results for Continuing Operations

 

Three Months Ended March 31, 2013 Compared To Three Months Ended March 31, 2012

 

Revenues

 

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

 

		Three Months Ended March 31,
		2013			2012			Change			Percent Change
		(In thousands, except percentages)
Revenues:
Crude oil sales		$	65,677		$	40,124		$	25,553		64	%
Natural gas sales		8,580			3,273			5,307			162	%
Natural gas liquids sales		3,989			4,408			(419		)	(10	)%
CO2 sales		61			25			36			144	%
		$	78,307		$	47,830		$	30,477		64	%
Sales volumes:
Crude oil (MBbls)		725.2			403.8			321.4			80	%
Natural gas (MMcf)		1,846.1			945.4			900.7			95	%
Natural gas liquids (MBbls)		74.7			68.8			5.9			9	%
Crude oil equivalent (MBoe)(1)		1,107.6			630.2			477.4			76	%
Average Sales Prices (before hedging)(2):
Crude oil (per Bbl)		$	90.56		$	99.37		$	(8.81	)	(9	)%
Natural gas (per Mcf)		4.65			3.46			1.19			34	%
Natural gas liquids (per Bbl)		53.40			64.07			(10.67		)	(17	)%
Crude oil equivalent (per Boe)(1)		70.64			75.86			(5.22		)	(7	)%
Average Sales Prices (after hedging)(2):
Crude oil (per Bbl)		$	88.28		$	95.86		$	(7.58	)	(8	)%
Natural gas (per Mcf)		4.73			3.68			1.05			29	%
Natural gas liquids (per Bbl)		53.40			64.07			(10.67		)	(17	)%
Crude oil equivalent (per Boe)(1)		69.29			73.94			(4.65		)	(6	)%

 

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

 

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

 

Revenues increased by 64%, to $78.3 million for the three months ended March 31, 2013 compared to $47.8 million for the three months ended March 31, 2012. Oil, natural gas, and natural gas liquids production increased 80%, 95%, and 9%, respectively, during the three months ended March 31, 2013, as compared to the three months ended March 31, 2012. During the period from March 31, 2012 through March 31, 2013, we completed 111 gross (107.4 net) wells in the Rockies and 48 gross (43.8 net) wells in Southern Arkansas. The increased volumes are a direct result of the $340.8 million expended for drilling and completion during the year ended December 31, 2012, and the $61.4 million expended during the three months ended March 31, 2013. Oil volumes

 

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increased by 80% in 2013, but were offset by a sales price decline of 9% from $99.37 per barrel to $90.56 per barrel for these three month periods, which accounted for the $25.6 million increase in revenues.  Increased natural gas volumes and prices of 95% and 34%, respectively, accounted for $4.2 million and $1.1 million, respectively, of the increase in natural gas revenues.   Natural gas liquids volumes increased by 9% in 2013, but were offset by a sales price decline of 17% from $64.07 per barrel to $53.40 per barrel for these three month periods which accounted for the $0.4 million decrease in revenues.  Our Wattenberg Field natural gas is sold as wet gas without processing and sells at a premium due to its very high BTU content. Our production of oil, natural gas, and natural gas liquids for the three months ended March 31, 2013 was approximately 65%, 28% and 7%, respectively.

 

Operating Expenses

 

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

 

		Three Months Ended March 31,
		2013			2012			Change			Percent Change
		(In thousands, except percentages)
Expenses:
Lease operating		$	11,131		$	7,107		$	4,024		57	%
Severance and ad valorem taxes		4,813			3,596			1,217			34	%
General and administrative		13,166			5,965			7,201			121	%
Depreciation, depletion and amortization		23,363			11,001			12,362			112	%
Exploration		562			1,190			(628		)	(53	)%
Operating expenses		$	53,035		$	28,859		$	24,176		84	%

 

Selected Costs ($ per Boe):
Lease operating		$	10.05		$	11.28		$	(1.23	)	(11	)%
Severance and ad valorem taxes		4.35			5.71			(1.36		)	(24	)%
General and administrative		11.89			9.47			2.42			26	%
Depreciation, depletion and amortization		21.09			17.46			3.63			21	%
Exploration		0.51			1.89			(1.38		)	(73	)%
Operating expenses		$	47.89		$	45.81		$	2.08		5	%

 

Lease Operating Expense.  Our lease operating expenses increased $4.0 million, or 57%, to $11.1 million for the three months ended March 31, 2013 from $7.1 million for the three months ended March 31, 2012 and decreased on a per barrel of oil equivalent basis from $11.28 per Boe to $10.05 per Boe. The aggregate increase in lease operating expense was related to increased production volumes attributable to our drilling program and the operation of an additional gas plant that was constructed during 2012 that came on line during February of 2013. Gas plant operating expense, which is a component of lease operating expense, increased $0.8 million, or 44%, to $2.6 million for the three month period ended March 31, 2013 from $1.8 million for the three month period ended March 31, 2012.  Lease operating expense increased during the three months ended March 31, 2013, because chemicals and treating, compressor rentals, and swabbing expenses were $0.6 million, $0.2 million, and $0.4 million higher, respectively, than the three months ended March 31, 2012. The decrease in lease operating expense on an equivalent basis was primarily related to the lower per unit operating costs of our horizontal wells in the Wattenberg Field.

 

Severance and ad valorem taxes.  Our severance and ad valorem taxes increased $1.2 million, or 34%, to $4.8 million for the three months ended March 31, 2013 from $3.6 million for the three months ended March 31, 2012. The increase was primarily related to a 76% increase in production volumes which was partially offset by a 7% decrease in realized prices per Boe during the three months ended March 31, 2013 as compared to the three months ended March 31, 2012.

 

General and administrative. Our general and administrative expense increased $7.2 million, or 121%, to $13.2 million for the three months ended March 31, 2013 from $6.0 million for the three months ended March 31, 2012. During the three months ended March 31, 2013, wages, benefits and professional services fees were $2.6 million higher than the three month period ended March 31, 2012 due to our increasing headcount as a result of our accelerated drilling program. During the three months ended March 31, 2013, legal fees were $0.4 million higher than the three month period ended March 31, 2012 due to fees associated with our secondary stock offering that was completed on February 6, 2013.  During the three months ended March 31, 2013, stock-based compensation charges were $3.7 million higher than the three month period ended March 31, 2012, $2.5 million of which were related to the February 2013 distribution of 73,197 shares of common stock that were fully vested and held by the BCEC Investment Trust to current and former employees. The BCEC Investment Trust was formed to hold shares of our common stock issued to Bonanza Creek Energy Company, LLC, our predecessor, in connection with our December 23, 2010 corporate restructuring.

 

Depletion, depreciation and amortization.  Our depletion, depreciation and amortization expense increased $12.4 million, or 112%, to $23.4 million for the three months ended March 31, 2013 from $11.0 million for the three months ended March 31, 2012.  Our depreciation, depletion and amortization expense per Boe produced increased $3.63, or 21% to $21.09 for the three months ended

 

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March 31, 2013 as compared to $17.46 for the three months ended March 31, 2012. This increase was primarily the result of a 76% increase in production period over period that was compounded by proved reserve and proved developed reserve volume growth that was not commensurate with the cost additions to the depletion base. At December 31, 2012, we revised our proved reserves downward by 6,938 MBoe due primarily to a combination of eliminating 50 locations from proved undeveloped reserves as a result of changes in focus from vertical to horizontal development and lower performance than expected from our vertical wells in the Wattenberg Field.

 

Exploration costs.  Our exploration expense decreased $0.6 million to $0.6 million for the three months ended March 31, 2013 from $1.2 million in the three months ended March 31, 2012. During the three months ended March 31, 2013, a seismic acquisition project was conducted in the Wattenberg Field of Colorado which resulted in charges of approximately $0.5 million. During the three months ended March 31, 2012, a seismic acquisition project was conducted in the North Park Basin of Colorado which resulted in charges of approximately $1.1 million.

 

Realized loss on settled commodity derivatives.  Realized losses on oil and gas hedging activities increased by $0.3 million from a loss of $1.2 million for the three months ended March 31, 2012 to a loss of $1.5 million for the three months ended March 31, 2013. The increase in realized loss period over period was primarily related to oil swaps covering approximately 2,300 Bbls per day with an average price of $86.82 compared to average benchmark oil prices of $94.37 during the three months ended March 31, 2013.  Approximately 3,700 Bbls per day were covered by costless collars during the three months ended March 31, 2013 and the average benchmark oil prices of $94.37 were above the put price but below the call price for these collars which resulted in no realized gains or losses.

 

Interest expense.  Our interest expense increased $1.4 million, or 250%, to $2.0 million for the three months ended March 31, 2013 from $0.6 million for the three months ended March 31, 2012. Average debt outstanding for the three months ended March 31, 2013 was $181.8 million as compared to $15.0 million for the three months ended March 31, 2012.

 

Income tax expense.  Our estimate for federal and state income taxes for the three months ended March 31, 2013 was $7.0 million from continuing operations as compared to $5.3 million for the three months ended March 31, 2012. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. Our effective tax rate for the periods ended March 31, 2013 and 2012 was 38.5%, which differs from the U.S. statutory income tax rate primarily due to the effects of state income taxes.

 

Results for Discontinued Operations

 

During June 2012, the Company began marketing, with an intent to sell, all of our oil and gas properties in California. The Company sold its interest in the Kern River, Greeley and Sargent fields during the third and fourth quarters of 2012. The Company is still marketing, with the intent to sell, all our oil and gas interests in the remaining field, Midway Sunset. Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. The Company determined that our intent to sell these properties qualifies for discontinued operations accounting and these assets have been presented as discontinued operations in the Company’s statements of operations.

 

The operating results before income taxes for our remaining California assets, located in the Midway Sunset Field, for the three month period ended March 31, 2013 was not material to the Company’s operations. The operating results for the four California fields for the three months ended March 31, 2012 were net revenues, operating expenses, and income from discontinued operations of $1.7 million, $1.6 million, and $0.1 million. Sales volumes for the three month periods ended March 31, 2013 and 2012 were 4.4 MBbls and 15.9 MBbls, respectively.

 

Liquidity and Capital Resources

 

Our primary sources of liquidity through first quarter 2013 have been proceeds from our initial public offering, borrowings under our credit facility, cash flows from operations, proceeds from the sale of non-core properties and our 2010 corporate restructuring. Our primary use of capital has been for the acquisition and development of oil and natural gas properties.

 

On December 15, 2011, the Company sold 10,000,000 shares of our common stock in our IPO 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.

 

In the second quarter 2012, we began the divestiture process of our non-core properties in California. The California properties were treated as assets held for sale, and production, revenue and expenses associated with these properties were removed

 

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from continuing operations and reported as discontinued operations. During 2012, we sold a majority of our properties in California, for approximately $9.3 million in aggregate.

 

On July 31, 2012, we acquired leases in the Wattenberg Field from the State of Colorado, State Board of Land Commissioners. We paid approximately $12 million at closing and will pay approximately $12 million on July 31st of each of the next four years. These future payments are secured by a letter of credit which reduced the borrowing base under our credit facility by $48 million as of March 31, 2013.

 

On April 6, 2012, the administrative agent under our credit facility was changed to KeyBank, National Association. On May 8, 2012, we entered into an amendment with the lenders under our credit facility to, among other things, and (i) increase our credit facility to $600 million, and (ii) make changes in the covenant applicable to hedging to allow greater flexibility for management to implement comprehensive hedging plans to adequately protect our operations and capital budgets. On October 30, 2012, our borrowing base was increased to $325 million, and as of March 31, 2013, we had $191.5 million outstanding, $48.0 million of letters of credit issued, and $85.5 million of borrowing capacity available under our credit facility. Our weighted-average interest rate on borrowings from our credit facility was 3.46% (excluding amortization of deferred financing costs and the accretion of our contractual obligation for land acquisition) during the three months ended March 31, 2013. On April 9, 2013, the Company sold $300,000,000 of 6.75% Senior Notes (the “Senior Notes”).  The net proceeds from the sale of the Senior Notes were approximately $293.2 million after deducting estimated expenses and underwriting discounts and commissions and the proceeds were used to repay all of the outstanding borrowings under our revolving credit facility, which was $191,500,000 as of April 9, 2013. Concurrent with the closing of the Senior Notes sale, our borrowing base under our revolving credit facility was reduced from $325 million to $250 million.

 

We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see “Item 3.—Quantitative and Qualitative Disclosures on Market Risks.”

 

We believe that the combination of our cash flow from operating activities, potential access to debt and capital markets, our current liquidity level and our ability to modify our future capital expenditure programs, will allow us to comply with all of our debt covenants, and meet the obligations from our ongoing operations.

 

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

 

		Three Months Ended March 31,
		2013			2012
		(In thousands)
Net cash provided by operating activities		$	38,292		$	17,685
Net cash provided by (used in) investing activities		(69,930		)	(34,740		)
Net cash provided by financing activities		30,540			14,965
Cash and cash equivalents		3,170			—
Acquisitions of oil and gas properties		934			294
Exploration and development of oil and gas properties and investment in gas processing facility		67,610			33,711

 

Cash flows provided by operating activities

 

Net cash provided by operating activities was $38.3 million for the three months ended March 31, 2013, compared to $17.7 million provided by operating activities for the three months ended March 31, 2012. The increase in cash from operating activities resulted primarily from an increase in revenues from increased production adjusted by cash utilized in connection with changes in working capital when comparing periods. Cash utilized by changes in working capital for the three months ended March 31, 2013 was $12.3 million compared to $12.4 million that was utilized by changes in working capital for the comparable period during 2012. Decreases in working capital of $12.3 million for the three months ended March 31, 2013 is comprised of increases in accounts receivable of $6.9 million and a decrease in accounts payable and accrued liabilities (exclusive of capital accruals) of $5.4 million. Decreases in working capital of $12.4 million for the three month period 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.

 

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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, 2013 was $69.9 million, compared to $34.7 million used in investing activities for the three months ended March 31, 2012. For the three months ended March 31, 2013, cash used for the acquisition of oil and gas properties was $0.9 million, and cash used for the development of oil and natural gas properties (including cash used for natural gas plant capital expenditures) was $67.6 million. For the three months ended March 31, 2012, cash used for the acquisition of oil and gas properties was $0.3 million, and cash used for the development of oil and natural gas properties (including cash used for natural gas plant capital expenditures) was $33.7 million.

 

Cash provided by financing activities

 

Net cash provided by financing activities for the three months ended March 31, 2013 was $30.5 million related to borrowings on our line of credit in the amount of $33.5 million partially offset by $2.9 million that was spent to satisfy employee tax withholdings for restricted stock that vested during the period. Net cash provided by financing activities for the three months ended March 31, 2012 was $15.0 million related to borrowings on our line of credit.

 

New Accounting Pronouncements

 

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

 

Critical Accounting Policies and Estimates

 

Information regarding our critical accounting policies and estimates is contained in Item 7 of our Annual Report on Form 10 - K for the fiscal year ended December 31, 2012.

 

Inflation

 

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the three month periods ended March 31, 2013 and 2012. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

 

Off-balance sheet arrangements

 

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

 

Forward-Looking Statements

 

This Report contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. These forward-looking statements may include projections and estimates concerning our capital expenditures, our liquidity and capital resources, our estimated revenues and losses, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, our business strategy and other statements concerning our operations, economic performance and financial condition. When used in this Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Forward-looking statements may include statements about:

 

·                  use of proceeds from the April 2013 offering of senior notes;

 

·                  our financial position;

 

·                  our cash flow and liquidity;

 

·                  anticipated amount and allocation of capital expenditures;

 

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

 

·                  anticipated sales volumes and percentage of liquids production;

 

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

 

·                  flexibility of our covenants under our credit agreement;

 

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

 

·                  adoption of accounting standards;

 

·                  compliance with local, state and federal regulation;

 

·                  fair value measurements;

 

·                  estimated discount rate;

 

·                  impact of derivative positions on our cash flows;

 

·                  inflationary pressures;

 

·                  creditworthiness of counter parties;

 

·                  change in internal controls and risk factors; and

 

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

 

We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. The actual results may differ materially from the results anticipated by these forward-looking statements.  Factors that could cause actual results to differ materially include, but are not limited to, the following:

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

·                  environmental risks;

 

·                  seasonal weather conditions and lease stipulations;

 

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

 

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

 

·                  availability of oilfield equipment, services and personnel;

 

·                  exploration and development risks;

 

·                  competition in the oil and natural gas industry;

 

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

 

·                  risks related to our derivative instruments;

 

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

 

·                  ability to maintain effective internal controls;

 

·                  access to adequate gathering systems 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 and other risks associated with perfecting title for mineral rights in some of our properties;

 

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

 

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

 

All forward-looking statements speak only as of the date of this report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. 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 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, 2012 would have been lower by approximately $161.6 million.

 

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

 

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

 

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

 

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

 

The following table provides a summary of derivative contracts as of March 31, 2013.

 

Settlement Period		Derivative Instrument		Total Notional Amount (Bbl/Mmbtu  per day)		Average Floor Price			Average Ceiling Price			Fair Market Value of Asset (Liability)
Oil
2013		Collar		3,164		$	88.38		$	101.58		$	(690,581	)
		Swap		2,809		88.69			88.69			(6,279,238		)
2014		Collar		3,589		86.72			95.53			(675,365		)
		Swap		625		90.80			90.80			(443,932		)
Gas
2013		Swap		504		6.40			6.40			250,220
												$	(7,838,896	)

 

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.

 

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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, 2013. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in SEC rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Based on the evaluation of our disclosure controls and procedures as of March 31, 2013, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

 

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

 

Changes in Internal Control over Financial Reporting

 

There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended March 31, 2013 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

PART II—OTHER INFORMATION

 

Item 1.         Legal Proceedings.

 

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other 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, we are aware of no material pending or overtly threatened legal actions against us.

 

Item 1A. Risk Factors.

 

Our business faces many risks. Any of the risk factors discussed in this Report, Item 1A of our 2012 Annual Report on Form 10-K 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, 2013, there has been no material change to such risk factors.

 

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

 

None.

 

Item 3.         Defaults Upon Senior Securities.

 

None.

 

Item 4.         Mine Safety Disclosures.

 

Not applicable.

 

Item 5.         Other Information.

 

None.

 

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Item 6.         Exhibits.

 

Exhibit No.		Description of Exhibit
4.1		Indenture, dated as of April 9, 2013, among the Company, the guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on April 11, 2013).
4.2		Registration Rights Agreement, dated April 9, 2013, among the Company, the guarantors named therein and Wells Fargo Securities, LLC, as representative of the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on April 11, 2013).
10.1		Amendment No. 6, dated as of March 29, 2013, to the Credit Agreement among the Company, KeyBank National Association, as Administrative Agent, and the lenders party thereto.
10.2		Purchase Agreement, dated April 4, 2013, among Bonanza Creek Energy, Inc., the subsidiary guarantors named therein and Wells Fargo Securities, LLC, as representative of the initial purchasers named therein (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 5, 2013).
10.3		Bonanza Creek Energy, Inc. Executive Change in Control and Severance Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 3, 2013).
10.4		Bonanza Creek Energy, Inc. Short Term Incentive Guidelines.
10.5		Form of Performance Share Agreement (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on March 29, 2013).
10.6		Form of Employment Letter Agreement (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 29, 2013).
10.7		Employment Letter Agreement, dated effective April 30, 2013, between Bonanza Creek Energy, Inc. and Michael R. Starzer (incorporated by referenced to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 3, 2013).
10.8		Employment Letter Agreement, dated effective April 30, 2013, between Bonanza Creek Energy, Inc. and Gary A. Grove (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on May 3, 2013).
10.9		Employment Letter Agreement, dated effective April 30, 2013, between Bonanza Creek Energy, Inc. and Patrick A. Graham (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on May 3, 2013).
10.10		Employment Letter Agreement, dated effective April 30, 2013, between Bonanza Creek Energy, Inc. and Christopher I. Humber (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on May 3, 2013).
31.1		Certification of the Principal Executive Officer pursuant to Rule 13a-14(a).
31.2		Certification of the Principal Financial Officer pursuant to Rule 13a-14(a).
32.1		Certification of the Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
32.2		Certification of the Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).
101		The following materials from the Bonanza Creek Energy, Inc. Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, 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.

 

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