CIVITAS RESOURCES, INC. - Quarter Report: 2012 September (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 September 30, 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. 40,057,248 shares of common stock were outstanding as of September 30, 2012.

 

 

 

PART I - FINANCIAL INFORMATION

 

Item 1.         Financial Statements.

 

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

 

(unaudited)

 

		September 30, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	4,845,583		$	2,089,674
Accounts receivable:
Oil and gas sales		29,520,522			17,850,719
Other		12,079,986			5,696,825
Prepaid expenses and other		1,515,475			1,868,016
Inventory of oilfield equipment		2,014,418			3,324,368
Derivative asset		2,714,219			1,297,403
Total current assets		52,690,203			32,127,005
OIL AND GAS PROPERTIES—using the successful efforts method of accounting:
Proved properties		718,962,011			547,878,188
Unproved properties		72,928,364			15,848,703
Wells in progress		69,819,751			23,783,142
		861,710,126			587,510,033
Less: accumulated depreciation, depletion and amortization		(66,199,440		)	(26,759,043		)
		795,510,686			560,750,990
NATURAL GAS PLANT		67,648,720			56,910,232
Less: accumulated depreciation		(2,820,328		)	(1,286,129		)
		64,828,392			55,624,103
PROPERTY AND EQUIPMENT		4,186,352			1,983,037
Less: accumulated depreciation		(611,272		)	(128,731		)
		3,575,080			1,854,306
Oil and gas properties held for sale less accumulated depreciation, depletion, and amortization		5,038,282			9,895,508
LONG-TERM DERIVATIVE ASSET		550,777			678,474
OTHER ASSETS, net		3,344,385			3,418,626
TOTAL ASSETS		$	925,537,805		$	664,349,012
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued expenses		$	62,993,900		$	27,068,326
Oil and gas revenue distribution payable		9,733,852			6,185,983
Contractual obligation for land acquisition		11,999,877			—
Derivative liability		5,339,006			5,276,633
Total current liabilities		90,066,635			38,530,942
LONG-TERM LIABILITIES:
Bank revolving credit		122,300,000			6,600,000
Contractual obligation for land acquisition		33,081,306			—
Ad valorem taxes		7,547,363			3,014,023
Derivative liability		820,565			2,579,175
Deferred income taxes, net		100,160,507			79,603,633
Asset retirement obligations		7,196,824			6,039,723
TOTAL LIABILITIES		361,173,200			136,367,496
COMMITMENTS AND CONTINGENCIES (Notes 7 and 8)
STOCKHOLDERS’ EQUITY:
Preferred stock, $.001 par value, 25,000,000 shares authorized, 0 outstanding		—			—
Common stock, $.001 par value, 225,000,000 shares authorized, 40,057,248 and 39,477,584 issued and outstanding, respectively		40,057			39,478
Additional paid-in capital		518,321,950			515,412,583
Retained earnings		46,002,598			12,529,455
Total stockholders’ equity		564,364,605			527,981,516
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	925,537,805		$	664,349,012

 

See accompanying notes to these consolidated financial statements.

 

2

 

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF OPERATIONS

 

(unaudited)

 

		Three Months Ended September 30,						Nine Months Ended September 30,
		2012			2011			2012			2011
NET REVENUES
Oil and gas sales		$	58,327,823		$	25,915,330		$	157,613,348		$	70,608,993
OPERATING EXPENSES:
Lease operating		8,444,403			4,686,328			22,506,131			12,040,775
Severance and ad valorem taxes		3,021,860			1,342,646			9,387,094			3,778,946
Exploration		6,359,222			18,608			9,563,876			566,210
Depreciation, depletion and amortization		17,715,763			6,329,995			41,751,296			18,472,491
Impairment of proved properties		268,500			623,039			268,500			623,039
General and administrative (including $1,445,910, $132,720, $2,912,248, and $132,720, respectively, of stock compensation)		9,335,266			4,179,301			22,410,369			9,115,956
Total operating expenses		45,145,014			17,179,917			105,887,266			44,597,417
INCOME FROM OPERATIONS		13,182,809			8,735,413			51,726,082			26,011,576
OTHER INCOME (EXPENSE):
Other loss		(90,640		)	(3,526		)	(82,930		)	(100,805		)
Interest expense		(1,125,634		)	(1,121,907		)	(2,341,843		)	(2,686,684		)
Unrealized (loss) gain in fair value of commodity derivatives		(9,007,034		)	8,268,367			2,985,356			7,095,912
Loss in fair value of commodity derivatives		(92,812		)	(519,287		)	(1,173,619		)	(2,353,187		)
Total other income (expense)		(10,316,120		)	6,623,647			(613,036		)	1,955,236
INCOME FROM CONTINUING OPERATIONS BEFORE TAXES		2,866,689			15,359,060			51,113,046			27,966,812
Income tax expense		(1,222,450		)	(8,527,646		)	(19,797,360		)	(13,176,124		)
INCOME FROM CONTINUING OPERATIONS		$	1,644,239		$	6,831,414		31,315,686			$	14,790,688
DISCONTINUED OPERATIONS (Note 3)
Loss from operations associated with oil and gas properties held for sale		(1,410,595		)	(3,754,649		)	(791,394		)	(3,635,226		)
Gain on sale of oil and gas properties		4,279,998			—			4,279,998			—
Income tax (expense) benefit		(1,092,755		)	1,756,587			(1,331,147		)	1,712,555
Income (loss) associated with oil and gas properties held for sale		1,776,648			(1,998,062		)	2,157,457			(1,922,671		)
NET INCOME		$	3,420,887		$	4,833,352		$	33,473,143		$	12,868,017
BASIC AND DILUTED INCOME PER SHARE
Income from continuing operations		$	0.04		$	0.23		$	0.79		$	0.51
Income (loss) from discontinued operations		$	0.05		$	(0.06	)	$	0.06		$	(0.07	)
Net income per common share		$	0.09		$	0.17		$	0.85		$	0.44
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—BASIC AND DILUTED		39,477,101			29,122,521			39,476,133			29,122,521

 

See accompanying notes to these consolidated financial statements.

 

3

 

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(unaudited)

 

		Nine Months Ended September 30,
		2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	33,473,143		$	12,868,017
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		43,900,774			21,083,067
Impairment of oil and gas properties		1,916,690			4,067,023
Deferred income taxes		20,556,874			11,463,569
Non-cash stock compensation		2,912,248			—
Exploration		7,378,612			—
Amortization of deferred financing costs		501,315			702,490
Valuation (increase) decrease in commodity derivatives		(2,985,356		)	(7,095,912		)
Gain on sale of oil and gas properties		(4,279,998		)	—
Other		70,563			92,352
(Increase) decrease in operating assets:
Accounts receivable		(18,152,964		)	(6,060,781		)
Prepaid expenses and other assets		352,541			(182,034		)
(Decrease) increase in operating liabilities:
Accounts payable and accrued liabilities		7,149,501			534,255
Settlement of asset retirement obligations		(146,125		)	(138,614		)
Net cash provided by operating activities		92,647,818			37,333,432
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of oil and gas properties		5,212,000			—
Acquisition of oil and gas properties		(12,809,268		)	(1,383,009		)
Exploration and development of oil and gas properties		(183,357,438		)	(91,906,848		)
Natural gas plant capital expenditures		(12,009,040		)	(18,063,482		)
Proceeds from note receivable		—			986,906
Decrease in restricted cash		252,580			—
Additions to property and equipment—non oil and gas		(2,203,315		)	(485,176		)
Net cash used in investing activities		(204,914,481		)	(110,851,609		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in bank revolving credit		115,700,000			145,900,000
Payment on bank revolving credit		—			(69,200,000		)
Deferred financing costs		(677,428		)	(3,029,254		)
Net cash provided by financing activities		115,022,572			73,670,746
NET INCREASE IN CASH AND CASH EQUIVALENTS		2,755,909			152,569
CASH AND CASH EQUIVALENTS:
Beginning of period		2,089,674			—
End of period		$	4,845,583		$	152,569
SUPPLEMENTAL CASH FLOW DISCLOSURE:
Cash paid for interest		$	1,224,331		$	1,876,866
Cash paid for income taxes		$	185,765		—
Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition		$	36,857,282		$	14,135,675
Contractual obligation for land acquisition		$	45,081,183		$	—

 

See accompanying notes to these consolidated financial statements.

 

4

 

Bonanza Creek Energy, Inc.

Notes to the Consolidated Financial Statements as of September 30, 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 September 30, 2012, the Company’s assets and operations are concentrated primarily in the Wattenberg field and North Park Basin in the Rocky Mountains and in southern Arkansas.

 

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 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, and Bonanza Creek Energy Midstream, LLC.  All significant intercompany accounts and transactions have been eliminated.

 

5

 

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. ACQUISTIONS AND DIVESTITURES:

 

On July 31, 2012, the Company acquired leases to approximately 5,600 net acres in the Wattenberg field from the State of Colorado, State Board of Land Commissioners. The Company 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 were discounted based on our effective borrowing rate to arrive at the purchase price of $57,000,000. These future payments are secured by a letter of credit and interest will be imputed on the future payments.

 

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. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted and a measurement for impairment is performed to expense any excess of carrying value over fair value less costs to sell. The Company determined that its intent to sell these properties qualifies for discontinued operations and, on August 31, 2012, the Company sold a portion of the properties for approximately $5.1 million and recorded a gain on the sale of oil and gas properties in the amount of $4.3 million related to this transaction. The carrying amounts of the major classes of assets and liabilities related to the operation of the remaining properties that are held for sale as of September 30, 2012 and December 31, 2011 are presented below:

 

		As of September 30, 2012			As of December 31, 2011
PROPERTY AND EQUIPMENT:
Oil and gas properties, successful efforts method:
Proved properties		$	7,799,582		$	13,060,597
Unproved properties		32,013			32,013
Wells in progress		30,629			167,198
Total property and equipment		7,862,224			13,259,808
Less accumulated depletion and depreciation		(2,823,942		)	(3,364,300		)
Net property and equipment		$	5,038,282		$	9,895,508
ASSET RETIREMENT OBLIGATIONS		$	769,700		$	975,562

 

Total revenues and costs and expenses, and the income associated with the operation of the oil and gas properties held for sale for the three and nine month periods ended September 30, 2012 and 2011 are presented below.

 

		Three Months Ended September 30			Three Months Ended September 30			Nine Months Ended September 30			Nine Months Ended September 30
		2012			2011			2012			2011
NET REVENUES:
Oil and gas sales		$	1,274,906		$	1,458,198		$	5,000,665		$	4,927,493
OPERATING EXPENSES:
Lease operating		451,795			795,428			1,853,085			2,419,715
Severance and ad valorem taxes		8,809			(1,000		)	124,298			81,449
Exploration		6,219			400			17,008			6,995
Depreciation, depletion and amortization		570,488			974,035			2,149,478			2,610,576
Impairment of proved properties		1,648,190			3,443,984			1,648,190			3,443,984
TOTAL COSTS AND EXPENSES		2,685,501			5,212,847			5,792,059			8,562,719
LOSS FROM OPERATIONS ASSOCIATED WITH OIL AND GAS PROPERTIES HELD FOR SALE		$	(1,410,595	)	$	(3,754,649	)	$	(791,394	)	$	(3,635,226	)

 

6

 

4. 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.

 

5. ACCOUNTS PAYABLE AND ACCRUED EXPENSES:

 

Accounts payable and accrued expenses contain the following:

 

		2012			2011
Drilling and completion costs		$	51,010,731		$	14,153,449
Accounts payable trade		267,213			4,976,979
Ad valorem taxes		190,627			1,781,021
Accrued general and administrative cost		5,039,156			1,713,708
Accrued initial public offering expenses		—			1,258,791
Lease operating expense		2,510,000			2,128,470
Accrued reclamation cost		400,000			400,000
Accrued interest		634,162			17,965
Accrued oil and gas hedging		314,537			353,897
Production taxes and other		2,627,474			284,046
		$	62,993,900		$	27,068,326

 

6. SENIOR SECURED REVOLVING CREDIT FACILITY:

 

Senior Secured Revolving Credit Facility—On May 8, 2012, the Company amended its senior secured revolving Credit Agreement, (the “Revolver”) dated March 29, 2011, with a syndication of banks, including KeyBank National Association as the administrative agent and issuing lender, which 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 Revolver had a $245 million borrowing base as of September 30, 2012 and is subject to semi-annual re-determinations in April and October of each year. The letter of credit that was issued to the Colorado State Board of Land Commissioners reduced the borrowing base 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,

 

7

 

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 September 30, 2012. The Revolver is collateralized by substantially all the Company’s assets and matures on September 15, 2016.

 

7. 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			Wattenberg Field Lease Acquisition			Line of Credit			Total
2012		$	297,265		$	—		—			$	297,265
2013		1,098,709			11,999,987			—			13,098,696
2014		1,085,740			11,999,987			—			13,085,727
2015		1,111,256			11,999,987			—			13,111,243
2016 and thereafter		2,235,743			11,999,987			122,300,000			136,535,730
		$	5,828,713		$	47,999,948		$	122,300,000		$	176,128,661

 

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 related 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—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.

 

In June 2011, Frank H. Bennett, a co-manager of BCOC, BCEC’s 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, the Company’s 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. The Company’s 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. An arbitration hearing commenced in July 2012 and it is not clear when a final decision will be rendered regarding the allegations or any potential recovery of legal fees. Mr. Starzer plans to continue to vigorously defend against Mr. Bennett’s claims. During the period from January 1, 2012 through September 30, 2012, the Company incurred approximately $2.5 million for the advancement of legal fees related to Mr. Bennett’s claims.

 

8. 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:

 

8

 

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.

 

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 September 30, 2012 by level within the fair value hierarchy:

 

		Fair Value Measurements Using
		Level 1			Level 2			Level 3
Commodity derivative assets		$	—		$	825,074		$	2,439,922
Commodity derivative liabilities		$	—		$	6,159,571		$	—

 

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 September 30, 2012:

 

		Derivative Asset			Derivative Liability
Beginning net asset (liability) balance		$	881,822		$	(1,115,595	)
Net increase in fair value		(654,780		)	4,978,506
Net realized (gain) on settlement		(231,511		)	(233,412		)
New derivatives		411,178			(1,596,286		)
Transfers in (out) of Level 3		—			—
Ending net asset (liability) balance		$	406,709		$	2,033,213

 

As of September 30, 2012, the Company’s derivative commodity contracts:

 

Contract Term		Notional Volume		Average Floor			Average Ceiling			Average Fixed Price
October 1 - December 31, 2012		77,956 Bbl./Month		$	90.00		$	106.05		—
January 1 - December 31, 2013		44,218 Bbl./Month		$	91.61		$	106.46		—
October 1 - December 31, 2012		49,400 Bbl./Month		—			—			$	88.78
January 1 - December 31, 2013		76,285 Bbl./Month		—			—			$	88.08
October 1 - December 31, 2012		323,103 MMBTU/Month		—			—			$	3.33
January 1 - October 31, 2013		15,481 MMBTU/Month		—			—			$	6.40

 

9

 

The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of September 30, 2012:

 

Derivatives		Balance Sheet Location		Fair Value
Asset
Commodity derivatives		Current derivative assets		$	2,714,219
Commodity derivatives		Long-term derivative assets		550,777
Liability
Commodity derivatives		Current derivative liability		(5,339,006		)
Commodity derivatives		Long-term derivative liability		(820,565		)
Total				$	(2,894,575	)

 

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.

 

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 nine months ended September 30, 2011. 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.

 

As a result of the impairment discussed in Note 11—Impairment of Proved Properties, the proved oil and gas properties measured at fair value within the accompanying balance sheets as of September 30, 2012 and 2011 were $4.6 million and $6.3 million, respectively.

 

9. STOCKHOLDERS’ EQUITY:

 

BCEI 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 $1,822,000 was recorded during the nine months ended September 30, 2012 and there was approximately $5,372,000 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 2.25 years.

 

BCEC Management Incentive Plan—As of September 30, 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.

 

BCEI Long Term Incentive Plan—On June 14, 2012, the Company granted 540,000 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 were valued at $15.38, 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. On August 15, 2012, the Company granted an additional 25,000 shares of restricted stock under the LTIP to a newly hired key employee. For accounting purposes, these shares were valued at $19.03, the closing price our common stock on the grant date. These shares will vest annually in one-third increments over 3 years and will be fully vested in August of 2015. On August 3, 2012, the Company granted an aggregate of 16,626 shares of common stock under the LTIP to the four independent members of our Board of Directors in 2011 for their 2011-2012 service.  For accounting purposes, these shares were valued at $18.04, the closing price our common stock on the grant date and vested upon grant and non-cash compensation expense of approximately $300,000 was recorded during the period from April 1, 2011 through June 30, 2012.  On August 3, 2012, the Company granted an aggregate of 16,908 shares of common stock under the LTIP to the four independent members of our Board of Directors in 2012 for their 2012-2013 service.  For accounting purposes, these shares were valued at $18.04, the closing price our common stock on the grant date and will vest immediately prior to the Company’s 2013 Annual Meeting. Non-cash compensation expense of approximately $73,000 was recorded during the quarter ended September 30, 2012.

 

10

 

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

 

11. IMPAIRMENT OF PROVED PROPERTIES:

 

The Company recorded $1.6 million of proved property impairments on the Company’s legacy California assets and $0.3 million of proved property impairment in one non-core field in Southern Arkansas for the nine months ended September 30, 2012.  The impairments of the Company’s legacy assets in California were related to anticipated sales proceeds that were lower than the net book value of the properties as of September 30, 2012 and the impairment of the non-core field in Southern Arkansas was related to a the well repair that did not restore the well to its previous production levels.

 

12.  SUBSEQUENT EVENTS:

 

On October 11, 2012, the Company sold Liberty Energy, LLC, which owned a 50% non-operated interest in the Sargent field in California, for approximately $3.2 million. During the quarter ended September 30, 2012, an impairment charge in the amount of $460,000 was recorded to write the field down to the sales price and no gain or loss was recorded on this transaction.

 

On October 30, 2012, the lenders under the Company’s senior secured revolving credit agreement redetermined the Company’s borrowing base resulting in an increase of the borrowing base to $325 million which excludes the value of the oil and gas properties held for sale.

 

11

 

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.

 

12

 

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 the Wattenberg Field and North Park Basins in Colorado (Rocky Mountain region) and southern Arkansas (Mid-Continent region).  In addition, we own and operate oil producing assets in the San Joaquin Basin (California region), which are currently classified as discontinued operations.  Our management team has extensive experience acquiring and operating oil and gas properties, which we believe will contribute to the development of our 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 asset base.

 

As demonstrated by our $165.5 million capital program in 2011 and our amended $298 million capital program in 2012, we are increasingly focused on exploiting our inventory of high-return projects. We also continue to seek acquisitions that will complement our existing core properties.

 

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.

 

Third Quarter 2012 Highlights:

 

For the third quarter 2012,

 

·                  Total production was 865 MBoe (9,403 Boe/d average daily production), a 122% increase over the third quarter 2011 and 9% over the second quarter 2012;

·                  Total revenue was $58.3 million, a 125% increase over the third quarter 2011 and 13% over the second quarter 2012; and

·                  Net income was $3.4 million, or $0.09 per diluted share.

 

Results for Continuing Operations

 

Three Months Ended September 30, 2012 Compared To Three Months Ended September 30, 2011

 

Revenues

 

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

 

		Three Months Ended September 30,
		2012			2011			Change			Percent Change
		(In thousands, except percentages)
Revenues:
Crude oil sales		$	49,755		$	19,085		$	30,670		161	%
Natural gas sales		4,668			3,598			1,070			30	%
Natural gas liquids sales		3,757			3,150			607			19	%
CO2 sales		148			82			66			80	%
Product revenues		$	58,328		$	25,915		$	32,413		125	%

 

		Three Months Ended September 30,
		2012		2011		Change		Percent Change
Sales volumes:
Crude oil (MBbls)		567.0		227.3		339.7		149	%
Natural gas (MMcf)		1,388.6		698.3		690.3		99	%
Natural gas liquids (MBbls)		66.6		45.3		21.3		47	%
Crude oil equivalent (MBoe)(1)		865.0		389.0		476.0		122	%

 

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

 

13

 

		Three Months Ended September 30,
		2012			2011			Change			Percent Change
Average Sales Prices (before hedging)(1):
Crude oil (per Bbl)		$	87.75		$	83.96		$	3.79		5	%
Natural gas (per Mcf)		3.36			5.15			(1.79		)	(35	)%
Natural gas liquids (per Bbl)		56.41			69.54			(13.13		)	(19	)%
Crude oil equivalent (per Boe)(2)		67.26			66.41			0.85			1	%

 

		Three Months Ended September 30,
		2012			2011			Change			Percent Change
Average Sales Prices (after hedging)(1):
Crude oil (per Bbl)		$	86.89		$	80.98		$	7.91		10	%
Natural gas (per Mcf)		3.65			5.38			(1.73		)	(32	)%
Natural gas liquids (per Bbl)		56.41			69.54			(13.08		)	(19	)%
Crude oil equivalent (per Boe)(2)		67.15			65.07			2.08			3	%

 

(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 125%, to $58.3 million for the three months ended September 30, 2012 compared to $25.9 million for the three months ended September 30, 2011. Oil, natural gas and natural gas liquids production increased 149%, 99% and 47%, respectively, during the three months ended September 30, 2012, as compared to the three months ended September 30, 2011. During the period from September 30, 2011 through September 30, 2012, we drilled and completed 108 gross (105.0 net) wells in the Rockies and 45 gross (40.0 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 $235.5 million expended during the nine months ended September 30, 2012. Oil prices increased from an average of $83.96 in 2011 to a per barrel rate of $87.75 in the comparable three month period that ended September 30, 2012.  Increased oil volumes of 149% accounted for $28.5 million of the total $30.7 million increase in revenues for the Company for the three month period ended September 30, 2012 compared to the same period in 2011.  Natural gas volumes increased by 99% in 2012, but were offset by a sales price decline of 35% from $5.15 per Mcf to $3.36 per Mcf for these three month periods. Natural gas liquids volumes increased by 47% in 2012 with a 19% decrease in prices period over period. Our Wattenberg field natural gas is sold 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 September 30, 2012 was approximately 66%, 27% and 7%, 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		$	8,444		$	4,686		$	3,758		80	%
Severance and ad valorem taxes		3,022			1,343			1,679			125	%
General and administrative		9,335			4,179			5,156			123	%
Depreciation, depletion and amortization		17,716			6,330			11,386			180	%
Impairment of oil and gas properties		269			623			(354		)	(57	)%
Exploration		6,359			19			6,340			33,368	%
Operating expenses		$	45,145		$	17,180		$	27,965		163	%

 

		Three Months Ended September 30,
		2012			2011			Change			Percent Change
Selected Costs ($ per Boe):
Lease operating		$	9.76		$	12.05		$	(2.29	)	(19	)%
Severance and ad valorem taxes		3.49			3.45			0.04			1	%
General and administrative		10.79			10.74			0.05			0	%
Depreciation, depletion and amortization		20.48			16.27			4.21			26	%
Impairment of oil and gas properties		0.31			1.60			(1.29		)	(80	)%
Exploration		7.35			0.05			7.30			14,600	%
Operating expenses		$	52.18		$	44.16		$	8.02		18	%

 

14

 

Lease Operating Expense.  Our lease operating expenses increased $3.8 million, or 80%, to $8.4 million for the three months ended September 30, 2012 from $4.7 million for the three months ended September 30, 2011 and decreased on an equivalent basis from $12.05 per Boe to $9.76 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 that came on line during September of 2011. Gas plant operating expense, which is a component of lease operating expense, increased $0.9 million, or 53%, to $2.5 million for the three month period ended September 30, 2012 from $1.6 million for the three month period ended September 30, 2011.  The increase in gas plant operating expense was primarily related to the replacement of a heat exchanger which cost approximately $0.7 million to procure and install. During the three months ended September 30, 2012, well servicing, rental equipment and other expenses were $1.5 million, $0.5 million and $0.7 million higher, respectively, than the three months ended September 30, 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 September 30, 2011 through September 30, 2012.

 

Severance and ad valorem taxes.  Our severance and ad valorem taxes increased $1.7 million, or 125%, to $3.0 million for the three months ended September 30, 2012 from $1.3 million for the three months ended September 30, 2011. The increase was primarily related to a 122% increase in production volumes which was further increased by a slight increase in realized prices per Boe during the three months ended September 30, 2012 as compared to the three months ended September 30, 2011. The increase in severance and ad valorem taxes for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011 was related to oil severance taxes and ad valorem taxes that were $1.2 million and $0.3 million, respectively, higher than the comparable period in the previous year.

 

Exploration costs.  Our exploration expense increased $6.3 million to $6.4 million in the three months ended September 30, 2012 from $19 thousand in the three months ended September 30, 2011. During the three months ended September 30, 2012, a seismic acquisition project in the North Park Basin of Colorado was completed which resulted in charges of approximately $0.3 million, delay rentals were $0.2 million, and two exploratory locations in the North Park basin were also charged to exploration expense. This resulted in a $5.8 million charge to our statement of operations during the three months ended September 30, 2012.

 

Depletion, depreciation and amortization.  Our depletion, depreciation and amortization expense increased $11.4 million, or 180%, to $17.7 million for the three months ended September 30, 2012 from $6.3 million for the three months ended September 30, 2011. Our depreciation, depletion and amortization expense per Boe produced increased $4.21, or 26% to $20.48 for the three months ended September 30, 2012 as compared to $16.27 for the three months ended September 30, 2011. This increase was primarily the result of a 122% increase in production period over period and the inclusion of additional horizontal Niobrara wells in the depletion base.  During the three months ended September 30, 2011 two horizontal Niobrara wells were included in the depletion base as compared to 25 horizontal Niobrara wells that were included in the depletion base during the three months ended September 30, 2012.

 

Impairment of oil and gas properties.  The Company recorded $0.3 million of proved property impairment in one non-core field in Southern Arkansas for the three months ended September 30, 2012. The Company recorded $0.6 million of proved property impairment in one non-core field in Southern Arkansas for the three months ended September 30, 2011.

 

General and administrative. Our general and administrative expense increased $5.2 million, or 123%, to $9.3 million for the three months ended September 30, 2012 from $4.2 million for the period ended September 30, 2011. During the three months ended September 30, 2012, wages, benefits and employee placement fees were $2.5 million higher than the three month period ended September 30, 2011 due to our increasing headcount 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 September 30, 2012, legal fees were $1.0 million higher and non-cash stock compensation charges for officers and certain employees were $1.4 million higher than the three month period ended September 30, 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 for the three months ended September 30, 2012 was $1.1 million which was commensurate with the three months ended September 30, 2011. Average debt outstanding for the three months ended September 30, 2012 was $121.1 million as compared to $108.1 million for the three months ended September 30, 2011.

 

Realized loss on settled commodity derivatives.  Realized losses on oil and gas hedging activities decreased by $0.4 million from a loss of $0.5 million for the three months ended September 30, 2011 to a loss of $0.1 million for the three months ended September 30, 2012. The change from a realized loss to a realized gain period over period was primarily related to commodity prices that were 1% higher during the three month period ended September 30, 2012.

 

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Income tax expense.  Our estimate for federal and state income taxes for the three months ended September 30, 2012 was $1.2 million from continuing operations, as compared to $8.5 million for the three months ended September 30, 2011. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. Our estimate of deferred income taxes for the three month period ended September 30, 2012 was $0.6 million and all income taxes for the three month period ended September 30, 2011 were deferred. Our effective tax rates differ from the U.S. statutory income tax rate primarily due to the effects of state income taxes.

 

Nine Months Ended September 30, 2012 Compared To Nine Months Ended September 30, 2011

 

Revenues

 

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

 

		Nine Months Ended September 30,
		2012			2011			Change			Percent Change
		(In thousands, except percentages)
Revenues:
Crude oil sales		$	133,880		$	52,253		$	81,627		156	%
Natural gas sales		12,238			9,279			2,959			32	%
Natural gas liquids sales		11,315			8,828			2,487			28	%
CO2 sales		180			249			(68		)	(27	)%
Product revenues		$	157,613		$	70,609		$	87,005		123	%

 

		Nine Months Ended September 30,
		2012		2011		Change		Percent Change
Sales volumes:
Crude oil (MBbls)		1,462.6		584.7		877.9		150	%
Natural gas (MMcf)		3,740.7		1,821.4		1,919.3		105	%
Natural gas liquids (MBbls)		202.4		128.8		73.6		57	%
Crude oil equivalent (MBoe)(1)		2,288.5		1,017.1		1,271.4		125	%

 

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

 

		Nine Months Ended September 30,
		2012			2011			Change			Percent Change
Average Sales Prices (before hedging)(1):
Crude oil (per Bbl)		$	91.53		$	89.37		$	2.16		2	%
Natural gas (per Mcf)		3.27			5.09			(1.82		)	(36	)%
Natural gas liquids (per Bbl)		55.90			68.54			(12.64		)	(18	)%
Crude oil equivalent (per Boe)(2)		68.79			69.18			(0.39		)	(1	)%

 

		Nine Months Ended September 30,
		2012			2011			Change			Percent Change
Average Sales Prices (after hedging)(1):
Crude oil (per Bbl)		$	90.16		$	84.53		$	5.63		7	%
Natural gas (per Mcf)		3.49			5.36			(1.87		)	(35	)%
Natural gas liquids (per Bbl)		55.90			68.54			(12.64		)	(18	)%
Crude oil equivalent (per Boe)(2)		68.28			66.87			1.41			2	%

 

(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.

 

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