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 June 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)

 

Delaware

 

61-1630631

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification No.)

 

 

 

410 17th Street, Suite 1400

 

 

Denver, Colorado

 

80202

(Address of principal executive offices)

 

(Zip Code)

 

(720) 440-6100

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  x Yes  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.

 

Large accelerated filer o

 

Accelerated filer o

 

 

 

Non-accelerated filer x

 

Smaller reporting company o

(Do not check if a smaller reporting company)

 

 

 

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. 40,011,894 shares of common stock were outstanding as of June 30, 2012.

 

 

 



 

PART I - FINANCIAL INFORMATION

 

Item 1.   Financial Statements.

 

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

 

(unaudited)

 

 

 

June 30,
2012

 

December 31,
2011

 

ASSETS

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

Cash and cash equivalents

 

$

 2,605,378

 

$

 2,089,674

 

Accounts receivable:

 

 

 

 

 

Oil and gas sales

 

24,346,613

 

17,850,719

 

Other

 

12,012,855

 

5,696,825

 

Prepaid expenses and other

 

1,899,507

 

1,868,016

 

Inventory of oilfield equipment

 

2,609,464

 

3,324,368

 

Derivative asset

 

7,369,944

 

1,297,403

 

Total current assets

 

50,843,761

 

32,127,005

 

OIL AND GAS PROPERTIES—using the successful efforts method of accounting:

 

 

 

 

 

Proved properties

 

647,233,892

 

547,878,188

 

Unproved properties

 

15,851,016

 

15,848,703

 

Wells in progress

 

68,775,281

 

23,783,142

 

 

 

731,860,189

 

587,510,033

 

Less: accumulated depreciation, depletion and amortization

 

(49,330,212

)

(26,759,043

)

 

 

682,529,977

 

560,750,990

 

NATURAL GAS PLANT

 

61,707,490

 

56,910,232

 

Less: accumulated depreciation

 

(2,287,223

)

 (1,286,129

)

 

 

59,420,267

 

55,624,103

 

PROPERTY AND EQUIPMENT

 

3,452,170

 

1,983,037

 

Less: accumulated depreciation

 

(405,824

)

(128,731

)

 

 

3,046,346

 

1,854,306

 

Oil and gas properties held for sale less accumulated depreciation, depletion, and amortization — Note 3

 

8,788,960

 

9,895,508

 

LONG-TERM DERIVATIVE ASSET

 

2,075,644

 

678,474

 

OTHER ASSETS, net

 

3,345,531

 

3,418,626

 

TOTAL ASSETS

 

$

810,050,486

 

$

664,349,012

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

Accounts payable and accrued expenses

 

$

64,431,194

 

$

27,068,326

 

Oil and gas revenue distribution payable

 

8,485,093

 

6,185,983

 

Derivative liability

 

2,536,623

 

5,276,633

 

Total current liabilities

 

75,452,910

 

38,530,942

 

LONG-TERM LIABILITIES:

 

 

 

 

 

Bank revolving credit

 

62,600,000

 

6,600,000

 

Ad valorem taxes

 

6,354,355

 

3,014,023

 

Derivative liability

 

796,506

 

2,579,175

 

Deferred income taxes, net

 

98,416,935

 

79,603,633

 

Asset retirement obligations

 

6,929,670

 

6,039,723

 

TOTAL LIABILITIES

 

250,550,376

 

136,367,496

 

COMMITMENTS AND CONTINGENCIES (Note 7)

 

 

 

 

 

STOCKHOLDERS’ EQUITY:

 

 

 

 

 

Preferred stock, $.001 par value, 25,000,000 shares authorized, 0 outstanding

 

 

 

Common stock, $.001 par value, 225,000,000 shares authorized, 40,011,894 and 39,477,584 issued and outstanding, respectively

 

40,012

 

39,478

 

Additional paid-in capital

 

516,878,387

 

515,412,583

 

Retained earnings

 

42,581,711

 

12,529,455

 

Total stockholders’ equity

 

559,500,110

 

527,981,516

 

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

 

$

810,050,486

 

$

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 
June 30

 

Six Months Ended June 30,

 

 

2012

 

2011

 

2012

 

2011

 

NET REVENUES

 

 

 

 

 

 

 

 

Oil and gas sales

$

 

51,455,094

 

$

24,151,668

 

$

99,285,525

 

$

44,693,663

 

OPERATING EXPENSES:

 

 

 

 

 

 

 

 

Lease operating

6,954,397

 

3,679,573

 

14,061,728

 

7,354,447

 

Severance and ad valorem taxes

2,769,425

 

1,396,514

 

6,365,234

 

2,436,300

 

Exploration

2,014,531

 

22,798

 

3,204,654

 

547,602

 

Depreciation, depletion and amortization

13,034,490

 

6,624,007

 

24,035,533

 

12,142,496

 

General and administrative (including $795,774, $60,000, $1,466,338, and $60,000,  respectively, of stock compensation)

 7,110,385

 

2,698,101

 

13,075,103

 

4,936,655

 

Total operating expenses

31,883,228

 

14,420,993

 

60,742,252

 

27,417,500

 

INCOME FROM OPERATIONS

19,571,866

 

9,730,675

 

38,543,273

 

17,276,163

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

Other income (loss)

45,437

 

(165,225

)

7,710

 

 (97,279

)

Interest expense

(654,693

)

(852,005

)

(1,216,209

)

(1,564,777

)

Unrealized (loss) in fair value of commodity derivatives

15,368,221

 

4,282,091

 

11,992,390

 

(1,172,455

)

Realized (loss) in fair value of commodity derivatives

130,332

 

(1,057,980

)

(1,080,807

)

(1,833,900

)

Total other income (loss)

14,889,297

 

2,206,881

 

9,703,084

 

(4,668,411

)

INCOME FROM CONTINUING OPERATIONS BEFORE TAXES

34,461,163

 

11,937,556

 

48,246,357

 

12,607,752

 

Deferred income taxes (Note 10)

(13,267,610

)

(4,400,505

)

(18,574,910

)

(4,648,478

)

INCOME FROM CONTINUING OPERATIONS

$

 

21,193,553

 

$

7,537,051

 

29,671,447

 

$

7,959,274

 

DISCONTINUED OPERATIONS (Note 3)

 

 

 

 

 

 

 

 

Income from operations associated with oil and gas properties held for sale

508,211

 

270,699

 

619,201

 

119,423

 

Deferred income taxes benefit

(195,661

)

(100,005

)

(238,392

)

(44,032

)

Income associated with oil and gas properties held for sale

312,550

 

170,694

 

380,809

 

75,391

 

NET INCOME

$

 

21,506,103

 

$

7,707,745

 

$

30,052,256

 

$

8,034,665

 

BASIC AND DILUTED INCOME PER SHARE

 

 

 

 

 

 

 

 

Income from continuing operations

$

 

0.53

 

$

0.25

 

$

0.75

 

$

0.28

 

Income (loss) from discontinued operations

$

 

0.01

 

$

0.01

 

$

0.01

 

$

 

WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK—BASIC AND DILUTED

39,474,011

 

29,122,521

 

39,475,797

 

29,122,521

 

 

See accompanying notes to these consolidated financial statements.

 

3



 

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(unaudited)

 

 

 

Six Months Ended
June 30,

 

 

 

2012

 

2011

 

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

Net income

 

$

30,052,256

 

$

8,034,665

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

Depreciation, depletion and amortization

 

25,614,523

 

13,779,037

 

Deferred income taxes

 

18,813,302

 

4,692,510

 

Non-cash stock compensation

 

1,466,338

 

60,000

 

Exploration

 

1,575,494

 

 

Amortization of deferred financing costs

 

464,377

 

447,197

 

Valuation (increase) decrease in commodity derivatives

 

(11,992,390

)

1,172,455

 

Other

 

3,334

 

(39,868

)

(Increase) decrease in operating assets:

 

 

 

 

 

Accounts receivable

 

(12,811,924

)

(4,219,346

)

Prepaid expenses and other assets

 

(31,491

)

(135,423

)

(Decrease) increase in operating liabilities:

 

 

 

 

 

Accounts payable and accrued liabilities

 

3,381,752

 

(1,884,356

)

Settlement of asset retirement obligations

 

(146,125

)

(80,435

)

Net cash provided by operating activities

 

56,389,446

 

21,826,436

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

Acquisition of oil and gas properties

 

(553,731

)

(777,621

)

Exploration and development of oil and gas properties

 

(102,945,699

)

(46,265,409

)

Natural gas plant capital expenditures

 

(6,510,563

)

(11,141,877

)

Proceeds from note receivable

 

 

986,906

 

Decrease in restricted cash

 

232,580

 

 

Additions to property and equipment—non oil and gas

 

(1,469,133

)

(214,021

)

Net cash used in investing activities

 

(111,246,546

)

(57,412,022

)

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

Increase in bank revolving credit

 

56,000,000

 

103,200,000

 

Payment on bank revolving credit

 

 

(65,800,000

)

Deferred financing costs

 

(627,196

)

(1,814,414

)

Net cash provided by financing activities

 

55,372,804

 

35,585,586

 

NET INCREASE IN CASH AND CASH EQUIVALENTS

 

515,704

 

 

CASH AND CASH EQUIVALENTS:

 

 

 

 

 

Beginning of period

 

2,089,674

 

 

End of period

 

$

2,605,378

 

$

 

SUPPLEMENTAL CASH FLOW DISCLOSURE:

 

 

 

 

 

Cash paid for interest

 

$

512,000

 

$

943,555

 

Changes in working capital related to drilling expenditures, natural gas plant expenditures, and property acquisition

 

$

39,577,503

 

$

4,694,941

 

 

See accompanying notes to these consolidated financial statements.

 

4



 

Bonanza Creek Energy, Inc.

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

 

2. BASIS OF PRESENTATION:

 

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

 

5



 

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

 

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

 

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

 

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

 

3. DIVESTITURES:

 

During June of 2012, the Company began marketing, with an intent to sell, all of its oil and gas properties in California.  In accordance with ASC Topic 360, 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 although the Company has not yet reached any definitive agreement with a counter party to sell the properties.  The carrying amounts of the major classes of assets and liabilities related to the operation of these properties that are held for sale as of June 30, 2012 and December 31, 2011 are presented below:

 

 

 

As of June 30,
2012

 

As of December
31, 2011

 

PROPERTY AND EQUIPMENT:

 

 

 

 

 

Oil and gas properties, successful efforts method:

 

 

 

 

 

Proved properties

 

$

13,061,985

 

$

13,060,597

 

Unproved properties

 

32,013

 

32,013

 

Wells in progress

 

581,387

 

167,198

 

Total property and equipment

 

13,675,385

 

13,259,808

 

Less accumulated depletion and depreciation

 

(4,886,425

)

(3,364,300

)

Net property and equipment

 

$

8,788,960

 

$

9,895,508

 

 

 

 

 

 

 

 

 

ASSET RETIREMENT OBLIGATIONS

 

$

1,014,974

 

$

975,562

 

 

6



 

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 six month periods ended June 30, 2012 and 2011 are presented below.

 

 

 

Three Months
Ended
June 30

 

Three Months
Ended
June 30

 

Six Months
Ended
June 30

 

Six Months
Ended
June 30

 

 

 

2012

 

2011

 

2012

 

2011

 

NET REVENUES:

 

 

 

 

 

 

 

 

 

Oil and gas sales

 

$

2,013,861

 

$

1,798,673

 

$

3,725,759

 

$

3,469,295

 

Total revenue

 

2,013,861

 

1,798,673

 

3,725,759

 

3,469,295

 

 

 

 

 

 

 

 

 

 

 

OPERATING EXPENSES:

 

 

 

 

 

 

 

 

 

Lease operating

 

733,547

 

685,137

 

1,401,290

 

1,624,287

 

Severance and ad valorem taxes

 

19,863

 

69,316

 

115,489

 

82,449

 

Exploration

 

187

 

5,935

 

10,789

 

6,595

 

Depreciation, depletion and amortization

 

752,053

 

767,586

 

1,578,990

 

1,636,541

 

TOTAL COSTS AND EXPENSES

 

1,505,650

 

1,527,974

 

3,106,558

 

3,349,872

 

 

 

 

 

 

 

 

 

 

 

INCOME FROM OPERATIONS ASSOCIATED WITH OIL AND GAS PROPERTIES HELD FOR SALE

 

$

508,211

 

$

270,699

 

$

619,201

 

$

119,423

 

 

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

 

$

53,730,952

 

$

14,153,449

 

Accounts payable trade

 

2,528,046

 

4,976,979

 

Ad valorem taxes

 

190,627

 

1,781,021

 

Accrued general and administrative cost

 

2,494,509

 

1,713,708

 

Accrued initial public offering expenses

 

 

1,258,791

 

Lease operating expense

 

2,361,200

 

2,128,470

 

Accrued reclamation cost

 

400,000

 

400,000

 

Accrued interest

 

257,797

 

17,965

 

Accrued oil and gas hedging

 

186,973

 

353,897

 

Production taxes and other

 

2,281,090

 

284,046

 

 

 

$

64,431,194

 

$

27,068,326

 

 

7



 

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 June 30, 2012 and is subject to semi-annual re-determinations in April and October of each year. The Revolver provides for commitment fees ranging from 0.375% to 0.50%, depending on utilization, and restricts, among other items, the payment of dividends, certain additional indebtedness, sale of assets, loans, and certain investments and mergers. The Revolver also contains certain financial covenants, which require the maintenance of a minimum current ratio and a minimum debt coverage ratio, as defined. The Company was in compliance with these covenants as of June 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

 

Line of
Credit

 

Total

 

2012

 

$

537,233

 

$

 

$

537,233

 

2013

 

1,098,709

 

 

1,098,709

 

2014

 

1,085,740

 

 

1,085,740

 

2015

 

1,111,256

 

 

1,111,256

 

2016 and thereafter

 

2,235,743

 

62,600,000

 

64,835,743

 

 

 

$

6,068,681

 

$

62,600,000

 

$

68,668,681

 

 

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—The Company may from time to time be involved in various legal actions arising in the normal course of business. During the second quarter of 2011, its Board of Directors formed a Special Litigation Committee comprised of three non-executive directors to investigate the merits of a demand for arbitration against its current President and Chief Executive Officer from the former Chairman of BCEC related to the management of BCOC and BCEC primarily during the 2005-2006 time period. These demands do not allege any wrongdoing by or claims against the Company. The Special Litigation Committee retained outside independent advisors to conduct the investigation and concluded that the allegations lack merit.  An arbitration hearing commenced in July 2012 and it is not clear when a final decision will be rendered.  Mr. Starzer plans to continue to vigorously defend against Mr. Bennett’s claims.  During the period from January 1, 2012 through June 30, 2012 the Company incurred approximately $1.2 million related to Mr. Bennett’s claims.

 

8



 

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:

 

Level 1:

 

Quoted prices are available in active markets for identical assets or liabilities;

Level 2:

 

Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; or

Level 3:

 

Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

 

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

 

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2012 by level within the fair value hierarchy:

 

 

 

Fair Value Measurements Using

 

 

 

Level 1

 

Level 2

 

Level 3

 

Commodity derivative assets

 

$

 

$

2,526,789

 

$

6,918,799

 

Commodity derivative liabilities

 

$

 

$

3,333,129

 

$

 

 

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 June 30, 2012:

 

 

 

Derivative Asset

 

Derivative Liability

 

Beginning net asset (liability) balance

 

$

881,822

 

$

(1,115,595

)

Net increase in fair value

 

330,830

 

8,014,163

 

Net realized (gain) on settlement

 

(181,946

)

(121,686

)

New derivatives

 

411,178

 

(1,299,967

)

Transfers in (out) of Level 3

 

 

 

Ending net asset (liability) balance

 

$

1,441,884

 

$

5,476,915

 

 

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

 

Contract
Term

 

Notional Volume

 

Average
Floor

 

Average
Ceiling

 

Average
Fixed
Price

 

July 1 - December 31, 2012

 

77,956 Bbl./Month

 

$

90.00

 

$

106.05

 

 

January 1 - December 31, 2013

 

34,218 Bbl./Month

 

$

92.10

 

$

108.91

 

 

July 1 - December 31, 2012

 

29,563 Bbl./Month

 

 

 

$

85.22

 

January 1 - December 31, 2013

 

16,285 Bbl./Month

 

 

 

$

81.72

 

July 1 - December 31, 2012

 

16,625 MMBTU/Month

 

 

 

$

6.75

 

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 June 30, 2012:

 

Derivatives

 

Balance Sheet Location

 

Fair Value

 

Asset

 

 

 

 

 

Commodity derivatives

 

Current derivative assets

 

$

7,369,944

 

Commodity derivatives

 

Long-term derivative assets

 

2,075,644

 

Liability

 

 

 

 

 

Commodity derivatives

 

Current derivative liability

 

(2,536,623

)

Commodity derivatives

 

Long-term derivative liability

 

(796,506

)

Total

 

 

 

$

6,112,459

 

 

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.

 

9. 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 its 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 $1,223,000 was recorded during the six months ended June 30, 2012 and there was approximately $6,019,000 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 2.5 years.

 

BCEC Management Incentive Plan—As of June 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.

 

On June 14, 2012, the Company granted 540,000 shares of restricted common stock under its 2011 Long Term Incentive Plan to officers and certain employees.  For accounting purposes, these shares were valued at $15.38, the closing price of its common stock on the grant date.  These shares will vest annually in one-third increments over approximately 2.7 years and will be fully vested in February of 2015.

 

10. 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. SUBSEQUENT EVENTS:

 

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 for approximately $60,000,000.  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 are secured by a letter of credit.

 

10



 

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

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2011 (the “2011 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q (this “Report”).

 

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

 

Forward-looking statements may include statements about:

 

·                  our ability to replace oil and natural gas reserves;

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

·                  our financial position;

·                  our cash flow and liquidity;

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

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

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

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

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

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

·                  environmental risks;

·                  drilling and operating risks;

·                  exploration and development risks;

·                  competition in the oil and natural gas industry;

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

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

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

·                  our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;

·                  costs associated with perfecting title for mineral rights in some of our properties;

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

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

 

All forward-looking statements speak only as of the date of this Report. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe

 

11



 

that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations below and under “Item 1A. Risk Factors” in our 2011 Annual Report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

Overview

 

Bonanza Creek Energy, Inc. (“BCEI” or, together with our consolidated subsidiaries, the “Company,” “we,” “us,” or “our”) is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States.  Our assets and operations are concentrated primarily in southern Arkansas (Mid-Continent region) and the Wattenberg Field and North Park Basins in Colorado (Rocky Mountain region).  In addition, we own and operate oil producing assets in the San Joaquin Basin (California region), 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 recently amended $298 million capital program for 2012, we are increasingly focused on exploiting our inventory of high-return locations.  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.

 

Second Quarter 2012 Highlights:

 

For the second quarter 2012,

 

·                  Total production was 793 MBoe (8,717 Boe/d average daily production), a 150% increase over the second quarter 2011 and 26% over the first quarter 2012;

·                  Total revenue was $51.5 million, a 113% increase over the second quarter 2011 and 8% over the first quarter 2012; and

·                  Net income was $21.2 million, or $0.53 per diluted share.

 

Results for Continuing Operations

 

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

 

Revenues

 

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

 

 

 

Three Months Ended June 30,

 

 

 

2012

 

2011

 

Change

 

Percent
Change

 

 

 

(In thousands, except percentages)

 

Revenues:

 

 

 

 

 

 

 

 

 

Crude oil sales

 

$

 44,000

 

$

 18,263

 

$

 25,737

 

141

%

Natural gas sales

 

4,296

 

2,755

 

1,541

 

56

%

Natural gas liquids sales

 

3,151

 

2,987

 

164

 

5

%

CO2 sales

 

8

 

146

 

(138

)

(94

)%

Product revenues

 

$

 51,455

 

$

 24,151

 

$

 27,304

 

113

%

 

 

 

Three Months Ended June 30,

 

 

 

2012

 

2011

 

Change

 

Percent
Change

 

Sales volumes:

 

 

 

 

 

 

 

 

 

Crude oil (MBbls)

 

491.8

 

188.7

 

303.1

 

161

%

Natural gas (MMcf)

 

1,406.6

 

544.6

 

862.0

 

158

%

Natural gas liquids (MBbls)

 

67.0

 

37.2

 

29.8

 

80

%

Crude oil equivalent (MBoe)(1)

 

793.2

 

316.7

 

476.5

 

150

%

 


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

 

12



 

 

 

Three Months Ended June 30,

 

 

 

2012

 

2011

 

Change

 

Percent
Change

 

Average Sales Prices (before hedging)(1):

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

89.47

 

$

96.78

 

$

(7.31

)

(8

)%

Natural gas (per Mcf)

 

3.05

 

5.06

 

(2.01

)

(40

)%

Natural gas liquids (per Bbl)

 

47.03

 

80.30

 

(33.27

)

(41

)%

Crude oil equivalent (per Boe)(2)

 

64.86

 

75.80

 

(10.94

)

(14

)%

 

 

 

Three Months Ended June 30,

 

 

 

2012

 

2011

 

Change

 

Percent
Change

 

Average Sales Prices (after hedging)(1):

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

89.26

 

$

90.36

 

$

(1.10

)

(1

)%

Natural gas (per Mcf)

 

3.22

 

5.34

 

(2.12

)

(40

)%

Natural gas liquids (per Bbl)

 

47.03

 

80.30

 

(33.27

)

(41

)%

Crude oil equivalent (per Boe)(2)

 

65.02

 

72.46

 

(7.44

)

(10

)%

 


(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 113%, to $51.5 million for the three months ended June 30, 2012 compared to $24.2 million for the three months ended June 30, 2011.  Oil, natural gas, and natural gas liquids production increased 161%, 158%, and 80%, respectively, during the three months ended June 30, 2012, as compared to the three months ended June 30, 2011.  During the period from June 30, 2011 through June 30, 2012, we drilled and completed 97 gross (91.9 net) wells in the Rockies and 49 gross (42.5 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 $149.6 million expended during the six months ended June 30, 2012.  Oil prices decreased from an average of $96.78 in 2011 to a per barrel rate of $89.47 in the comparable three month period that ended June 30, 2012.  Increased oil volumes of 161% accounted for $25.7 million of the total $27.3 million increase in revenues for the Company for the three month period ended June 30, 2012 compared to the same period in 2011.  Natural gas volumes increased by 158% in 2012, but were offset by a sales price decline of 40% from $5.06 per Mcf to $3.05 per Mcf for these three month periods. Natural gas liquids volumes increased by 80% in 2012, but were offset by a sales price decline of 41% from $80.30 per barrel to $47.03 per barrel for these three month periods.  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 June 30, 2012 was approximately 62%, 30% and 8%, 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

 

$

6,954

 

$

3,680

 

$

3,274

 

89

%

Severance and ad valorem taxes

 

2,769

 

1,396

 

1,373

 

98

%

General and administrative

 

7,110

 

2,698

 

4,412

 

164

%

Depreciation, depletion and amortization

 

13,035

 

6,624

 

6,411

 

97

%

Exploration

 

2,015

 

23

 

1,992

 

8,661

%

Operating expenses

 

$

31,883

 

$

14,421

 

$

17,462

 

121

%

 

 

 

Three Months Ended June 30,

 

 

 

2012

 

2011

 

Change

 

Percent
Change

 

Selected Costs ($ per Boe):

 

 

 

 

 

 

 

 

 

Lease operating

 

$

8.77

 

$

11.62

 

$

(2.85

)

(25

)%

Severance and ad valorem taxes

 

3.49

 

4.41

 

(0.92

)

(21

)%

General and administrative

 

8.96

 

8.52

 

0.44

 

5

%

Depreciation, depletion and amortization

 

16.43

 

20.92

 

(4.49

)

(21

)%

Exploration

 

2.54

 

0.07

 

2.47

 

3,529

%

Operating expenses

 

$

40.19

 

$

45.54

 

$

(5.35

)

(12

)%

 

13



 

Lease Operating Expense.  Our lease operating expenses increased $3.3 million, or 89%, to $7.0 million for the three months ended June 30, 2012 from $3.7 million for the three months ended June 30, 2011 and decreased on an equivalent basis from $11.62 per Boe to $8.77 per Boe.  The increase in lease operating expense was related to increased production volumes attributable to our drilling program and the operation of an additional gas plant that was constructed during 2011, but not operational during the three months ended June 30, 2011.  Gas plant operating expense, which is a component of lease operating expense, increased $0.6 million, or 36%, to $2.1 million for the three month period ended June 30, 2012 from $1.5 million for the three month period ended June 30, 2011.  Significant increases in gas plant operating expenses period over period were for compression and rental equipment and repairs and maintenance which were $0.3 million and $0.2 million, respectively.  During the three months ended June 30, 2012, well servicing, rental equipment, and other expenses were $1.8 million, $0.2 million, and $0.2 million higher, respectively, than the three months ended June 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 June 30, 2011 through June 30, 2012.

 

Severance and ad valorem taxes.  Our severance and ad valorem taxes increased $1.4 million, or 98%, to $2.8 million for the three months ended June 30, 2012 from $1.4 million for the three months ended June 30, 2011.  The increase was primarily related to a 150% increase in production volumes partially offset by a 14% decrease in realized prices per Boe during the three months ended June 30, 2012 as compared to the three months ended June 30, 2011.  The increase in severance and ad valorem taxes for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011 was related to oil severance taxes and ad valorem taxes that were $0.4 million and $1.0 million, respectively, higher than the comparable period in the previous year.

 

Exploration costs.  Our exploration expense increased $2.0 million, or 8,661%, to $2.0 million in the three months ended June 30, 2012 from $23 thousand in the three months ended June 30, 2011.  During the three months ended June 30, 2012, a seismic acquisition project in the North Park Basin of Colorado was reprocessed which resulted in charges of approximately $0.5 million. One exploratory location where surface casing had been set and minimal work performed was also charged to exploration expense because the work had been performed during 2010 and management had no current plans to complete a well on this location.  This resulted in a $1.5 million non-cash charge to our statement of operations during the three months ended June 30, 2012.

 

Depletion, depreciation and amortization.  Our depletion, depreciation and amortization expense increased $6.4 million, or 97%, to $13.0 million for the three months ended June 30, 2012 from $6.6 million for the three months ended June 30, 2011.  This increase was the result of a 150% increase in production period over period.  Our depreciation, depletion and amortization expense per Boe produced decreased $4.49, or 21% to $16.43 for the three months ended June 30, 2012 as compared to $20.92 for the three months ended June 30, 2011.  This decrease to depreciation, depletion and amortization expense per Boe resulted from additions to the proved developed reserve base from accretive drilling during the period from July 1, 2011 through June 30, 2012.

 

General and administrative. Our general and administrative expense increased $4.4 million, or 164%, to $7.1 million for the three months ended June 30, 2012 from $2.7 million for the period ended June 30, 2011. During the three months ended June 30, 2012, wages, benefits and employee placement fees were $2.5 million higher than the three month period ended June 30, 2011 due to our headcount increasing by approximately 50 employees, or 69% period over period, as the result of our accelerated drilling program and the addition of accounting, legal and IT positions that were previously outsourced.  During the three months ended June 30, 2012, legal fees were $0.9 million higher, software maintenance was $0.1 million higher and non-cash stock compensation charges for officers and certain employees were $0.7 million higher than the three month period ended June 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 decreased $0.2 million, or 23%, to $0.7 million for the three months ended June 30, 2012 from $0.9 million for the three months ended June 30, 2011.  The decrease resulted from a decrease in the average debt outstanding for the three months ended June 30, 2012 compared to the three months ended June 30, 2011.  Average debt outstanding for the three months ended June 30, 2012 was $44.7 million as compared to $74.0 million for the three month ended June 30, 2011.

 

Realized loss on settled commodity derivatives.  Realized losses on oil and gas hedging activities decreased by $1.2 million from a loss of $1.1 million for the three months ended June 30, 2011 to a gain of $0.1 million for the three months ended June 30, 2012.  The change from a realized loss to a realized gain period over period was primarily related to commodity prices that were 14% lower during the three month period ended June 30, 2012.  Hedging gains for the month of June were $0.8 million as the NYMEX sweet

 

14



 

crude oil price averaged $82.41 during June of 2012 as compared to our oil hedges which had an average floor of $88.61 per barrel during June of 2012.

 

Income tax expense.  Our estimate for federal and state income taxes for the three months ended June 30, 2012 was $13.3 million from continuing operations as compared to $4.4 million for the three months ended June 30, 2011.  We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation.  All income taxes for the periods ended June 30, 2012 and 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.

 

Six Months Ended June 30, 2012 Compared To Six Months Ended June 30, 2011

 

Revenues

 

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

 

 

 

Six Months Ended June 30,

 

 

 

2012

 

2011

 

Change

 

Percent
Change

 

 

 

(In thousands, except percentages)

 

Revenues:

 

 

 

 

 

 

 

 

 

Crude oil sales

 

$

 84,124

 

$

 33,169

 

$

 50,955

 

154

%

Natural gas sales

 

7,569

 

5,681

 

1,888

 

33

%

Natural gas liquids sales

 

7,559

 

5,678

 

1,881

 

33

%

CO2 sales

 

33

 

166

 

(133

)

(80

)%

Product revenues

 

$

 99,285

 

$

 44,694

 

$

 54,591

 

122

%

 

 

 

Six Months Ended June 30,

 

 

 

2012

 

2011

 

Change

 

Percent
Change

 

Sales volumes:

 

 

 

 

 

 

 

 

 

Crude oil (MBbls)

 

895.6

 

357.4

 

538.2

 

151

%

Natural gas (MMcf)

 

2,352.1

 

1,123.1

 

1,229.0

 

109

%

Natural gas liquids (MBbls)

 

135.8

 

83.4

 

52.4

 

63

%

Crude oil equivalent (MBoe)(1)

 

1,423.4

 

628.0

 

795.4

 

127

%

 


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

 

 

 

Six Months Ended June 30,

 

 

 

2012

 

2011

 

Change

 

Percent
Change

 

Average Sales Prices (before hedging)(1):

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

93.93

 

$

92.81

 

$

1.12

 

1

%

Natural gas (per Mcf)

 

3.22

 

5.06

 

(1.84

)

(36

)%

Natural gas liquids (per Bbl)

 

55.66

 

68.08

 

(12.42

)

(18

)%

Crude oil equivalent (per Boe)(2)

 

69.73

 

70.90

 

(1.17

)

(2

)%

 

 

 

Six Months Ended June 30,

 

 

 

2012

 

2011

 

Change

 

Percent
Change

 

Average Sales Prices (after hedging)(1):

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

92.23

 

$

86.78

 

$

5.45

 

6

%

Natural gas (per Mcf)

 

3.40

 

5.34

 

(1.94

)

(36

)%

Natural gas liquids (per Bbl)

 

55.66

 

68.08

 

(12.42

)

(18

)%

Crude oil equivalent (per Boe)(2)

 

68.97

 

67.98

 

0.99

 

1

%

 


(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.

 

15



 

Revenues increased by 122%, to $99.3 million for the six months ended June 30, 2012 compared to $44.7 million for the six months ended June 30, 2011.  Oil, natural gas, and natural gas liquids production increased 151%, 109%, and 63%, respectively, during the six months ended June 30, 2012, as compared to the six months ended June 30, 2011.  During the period from June 30, 2011 through June 30, 2012, we drilled and completed 97 gross (91.9 net) wells in the Rockies and 49 gross (42.5 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 $149.8 million expended during the six months ended June 30, 2012.  Oil prices increased from an average of $92.81 in 2011 to a per barrel rate of $93.93 in the comparable six month period that ended June 30, 2012.  The combination of increased oil volumes and prices accounted for $51.0 million of the total $54.6 million increase in revenues for the Company for the six month period ended June 30, 2012 compared to the same period in 2011.  Natural gas volumes increased by 109% in 2012, but were offset by a sales price decline of 36% from $5.06 per Mcf to $3.22 per Mcf for these six month periods.  Natural gas liquid volumes increased by 63% in 2012, but were offset by a salesprices decline of 18% from $68.08 per Bbl to $55.66 per Bbl for these six month periods.  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 six months ended June 30, 2012 was approximately 63%, 27% and 10%, 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

 

$

14,062

 

$

7,354

 

$

6,708

 

91

%

Severance and ad valorem taxes

 

6,365

 

2,436

 

3,929

 

161

%

General and administrative

 

13,075

 

4,937

 

8,138

 

165

%

Depreciation, depletion and amortization

 

24,036

 

12,142

 

11,894

 

96

%

Exploration

 

3,205

 

548

 

2,657

 

485

%

Operating expenses

 

$

60,743

 

$

27,417

 

$

33,326

 

122

%

 

 

 

Six Months Ended June 30,

 

 

 

2012

 

2011

 

Change

 

Percent
Change

 

Selected Costs ($ per Boe):

 

 

 

 

 

 

 

 

 

Lease operating

 

$

9.88

 

$

11.71

 

$

(1.83

)

(16

)%

Severance and ad valorem taxes

 

4.47

 

3.88

 

0.59

 

15

%

General and administrative

 

9.19

 

7.86

 

1.33

 

17

%

Depreciation, depletion and amortization

 

16.89

 

19.33

 

(2.44

)

(13

)%

Exploration

 

2.25

 

0.87

 

1.38

 

159

%

Operating expenses

 

$

42.68

 

$

43.65

 

$

(0.97

)

(2

)%

 

Lease Operating Expense.  Our lease operating expenses increased $6.7 million, or 91%, to $14.1 million for the six months ended June 30, 2012 from $7.4 million for the six months ended June 30, 2011 and decreased on an equivalent basis from $11.71 per Boe to $9.88 per Boe.  The increase in lease operating expense was related to increased production volumes attributable to our drilling program and the operation of an additional gas plant that was constructed during 2011, but not operational during the six months ended June 30, 2011.  Gas plant operating expense, which is a component of lease operating expense, increased $1.4 million, or 55%, to $4.0 million for the six month period ended June 30, 2012 from $2.6 million for the six month period ended June 30, 2011.  Significant increases in gas plant operating expenses period over period were for compression and rental equipment, repairs and maintenance, and utilities and electrical which were $0.8 million, $0.4 million, and $0.3 million, respectively.  During the six months ended June 30, 2012, well servicing, rental equipment, pumping and gauging, and other expenses were $2.9 million, $0.4 million, $0.3 million and $0.3 million higher, respectively, than the six months ended June 30, 2011.  The decrease in lease operating expense on an equivalent basis was primarily related to accretive drilling and the lower per unit operating costs of the wells drilled during the period from June 30, 2011 through June 30, 2012.

 

Severance and ad valorem taxes.  Our severance and ad valorem taxes increased $4.0 million, or 161%, to $6.4 million for the six months ended June 30, 2012 from $2.4 million for the six months ended June 30, 2011.  The increase was primarily related to a 127% increase in production volumes partially offset and a 2% decrease in realized prices per Boe during the six months ended June 30, 2012 as compared to the six months ended June 30, 2011.  The increase in severance and ad valorem taxes on a Boe basis for the six months ended June 30, 2012 as compared to the six months ended June 30, 2011 was related to oil severance taxes and ad valorem taxes that were $2.5 million and $1.2 million, respectively, higher than the comparable period in the previous year.

 

16



 

Exploration costs.  Our exploration expense increased $2.7 million, or 485%, to $3.2 million in the six months ended June 30, 2012 from $0.5 million in the six months ended June 30, 2011.  During the six months ended June 30, 2012, a seismic acquisition project was conducted in the North Park Basin of Colorado to assist the scientific staff in identifying the appropriate drill locations and plans for future development.  This survey was reprocessed during the second quarter which resulted in additional charges of approximately $0.5 million. In addition to the seismic survey, one exploratory location where surface casing had been set and minimal work performed was charged to exploration expense because the work had been performed during 2010 and management had no current plans to complete a well on this location.  This resulted in a $1.5 million non-cash charge to our statement of operations during the six months ended June 30, 2012. During the six months ended June 30, 2011, we acquired 7,700 acres of 3-D seismic data on the eastern edge of the Wattenberg field in Weld County Colorado to help evaluate our Niobrara oil shale acreage.

 

Depletion, depreciation and amortization.  Our depletion, depreciation and amortization expense increased $11.9 million, or 96%, to $24.0 million for the six months ended June 30, 2012 from $12.1 million for the six months ended June 30, 2011.  This increase was the result of a 127% increase in production period over period.  Our depreciation, depletion and amortization expense per Boe produced decreased $2.44, or 13% to $16.89 for the six months ended June 30, 2012 as compared to $19.33 for the six months ended June 30, 2011.  This decrease to depreciation, depletion and amortization expense per Boe resulted from additions to the proved developed reserve base from accretive drilling during the period from July 1, 2011 through June 30, 2012.

 

General and administrative. Our general and administrative expense increased $8.1 million, or 165%, to $13.1 million for the six months ended June 30, 2012 from $5.0 million for the six months ended June 30, 2011. During the six months ended June 30, 2012, wages, benefits and employee placement fees were $4.9 million higher than the six month period ended June 30, 2011 due to our headcount increasing by approximately 50 employees, or 74% period over period, as the result of our accelerated drilling program and the addition of accounting, legal and IT positions that were previously outsourced. During the six months ended June 30, 2012, accounting fees were $0.4 million higher due to a one-time payment that was made to our outsource accounting provider to terminate our agreement with them. Also during the six months ended June 30, 2012, legal fees were $1.0 million higher, franchise taxes were $0.3 million higher and non-cash stock compensation charges for officers and certain employees were $1.4 million higher than the six month period ended June 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 decreased $0.4 million, or 22%, to $1.2 million for the six months ended June 30, 2012 from $1.6 million for the six months ended June 30, 2011.  The decrease resulted from a decrease in the average debt outstanding for the six months ended June 30, 2012 compared to the six months ended June 30, 2011.  Average debt outstanding for the six months ended June 30, 2012 was $29.9 million as compared to $67.7 million for the six months ended June 30, 2011.

 

Realized loss on settled commodity derivatives.  Realized losses on oil and gas hedging activities decreased by $0.7 million from a loss of $1.8 million for the six months ended June 30, 2011 to a loss of $1.1 million for the six months ended June 30, 2012.  The decrease in the realized loss period over period was primarily related to hedging gains for the month of June which were $0.8 million as the NYMEX sweet crude oil price averaged $82.41 per barrel during June of 2012 as compared to our oil hedges which had an average floor of $88.61 per barrel during June of 2012.

 

Income tax expense.  Our estimate for federal and state income taxes for continuing operations for the six months ended June 30, 2012 was $18.6 million as compared to $4.6 million for the six months ended June 30, 2011.  We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation.  All income taxes for the periods ended June 30, 2012 and 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.

 

Results for Discontinued Operations

 

During June of 2012, the Company began marketing, with an intent to sell, all of our 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 our intent to sell these properties qualifies for discontinued operations accounting and these assets will be presented as discontinued operations in the Company’s statements of operations.

 

The operating results before income taxes for our California properties for the three month period ended June 30, 2012 were net revenues, operating expenses, and income from discontinued operations of $2.0 million, $1.5 million and $0.5 million, respectively, as compared to net revenues, operating expenses, and income from discontinued operations of $1.8 million, $1.5 million, and $0.3 million for the three month period ended June 30, 2011.  Sales volumes for the three month periods ended June 30, 2012 and 2011 were 20.6 MBbls and 16.3 MBbls, respectively.

 

The operating results before income taxes for our California properties for the six month period ended June 30, 2012 were net revenues, operating expenses, and income from discontinued operations of $3.7 million, $3.1 million and $0.6 million, respectively, as compared to net

 

17



 

revenues, operating expenses, and income from discontinued operations of $3.5 million, $3.4 million, and $0.1 million for the six month period ended June 30, 2011.  Sales volumes for the six month periods ended June 30, 2012 and 2011 were 36.6 MBbls and 34.7 MBbls, respectively.

 

Liquidity and Capital Resources

 

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

 

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

 

On April 6, 2012, the administrative agent under our credit facility was changed to KeyBank, National Association.  On May 8, 2012, we entered into an amendment with the lenders under our credit facility to, among other things, (i) increase our credit facility to $600 million and borrowing base to $245 million, and (ii) make changes in the covenant applicable to hedging to allow greater flexibility for management to implement comprehensive hedging plans to adequately protect the Company’s operations and capital budgets.  As of June 30, 2012, we had $62.6 million outstanding and $182.4 million of borrowing capacity available under our credit facility.

 

On July 31, 2012, the Company acquired leases in the Wattenberg field from the State of Colorado, State Board of Land Commissioners for approximately $60,000,000.  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 are secured by a letter of credit which reduced our availability under the borrowing base.

 

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

 

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

 

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

 

 

 

Six Months Ended June 30,

 

 

 

2012

 

2011

 

 

 

(In thousands)

 

Net cash provided by operating activities

 

$

 56,389

 

$

 21,826

 

Net cash provided by (used in) investing activities

 

(111,247

)

(57,412

)

Net cash provided by financing activities

 

55,373

 

35,586

 

Cash and cash equivalents

 

2,605

 

 

Acquisitions of oil and gas properties

 

554

 

778

 

Exploration and development of oil and gas properties and investment in gas processing facility

 

109,456

 

57,407

 

 

Cash flows provided by operating activities

 

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

 

Net cash provided by operating activities was $56.4 million for the six months ended June 30, 2012, compared to $21.8 million provided by operating activities for the six months ended June 30, 2011.  The increase in operating activities results primarily

 

18



 

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 six months ended June 30, 2012 was $9.6 million compared to $6.3 million that was utilized by changes in working capital for the comparable period during 2011.  Decreases in working capital of $9.6 million for the six months ended June 30, 2012 is comprised of increases in accounts receivable of $12.8 million offset by an increase in accounts payable and accrued liabilities (exclusive of capital accruals) of $3.4 million.  Decreases in working capital of $6.3 million for the six month period ended June 30, 2011 is comprised of increases in accounts receivable of $4.2 million and decreases in accounts payable and accrued liabilities (exclusive of capital accruals) of $1.9 million.

 

Cash flows used in investing activities

 

Expenditures for development of oil and natural gas properties and natural gas plants are the primary use of our capital resources.  Net cash used in investing activities for the six months ended June 30, 2012 was $111.2 million, compared to $57.4 million used in investing activities for the six months ended June 30, 2011.  For the six months ended June 30, 2012, cash used for the development of oil and natural gas properties was $109.5 million including $6.5 million for a natural gas plant.  In the Wattenberg field during the six months ended June 30, 2012, we drilled and completed 54 gross (50.5 net) wells of which 13 gross (12.2 net) were horizontal Niobrara wells.  In Southern Arkansas, we drilled and completed drilled 24 gross (19.5 net) vertical wells.

 

Cash provided by financing activities

 

Net cash provided by financing activities for the six months ended June 30, 2012 was $55.4 million related to net borrowings on our line of credit in the amount of $56.0 million offset by deferred financing costs of $0.6 million.  Net cash provided by financing activities for the six months ended June 30, 2011 was $35.6 million related to net borrowings on our line of credit in the amount of $37.4 million offset by deferred financing costs of $1.8 million.

 

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

 

New Accounting Pronouncements

 

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

 

Critical Accounting Policies and Estimates

 

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

 

Inflation

 

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the six month periods ended June 30, 2012 and 2011.  Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

 

Off-balance sheet arrangements

 

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

 

19



 

Item 3.    Quantitative and Qualitative Disclosures About Market Risk.

 

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

 

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

 

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

 

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

 

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

 

The following table provides a summary of derivative contracts as of June 30, 2012.

 

Settlement
Period

 

Derivative
Instrument

 

Total
Notional
Amount
(Bbl/Mmbtu)

 

Average
Floor
Price

 

Average
Ceiling
Price

 

Fair Market
Value of
Asset
(Liability)

 

 

 

 

 

 

 

 

 

 

 

(In
thousands)

 

Oil

 

 

 

 

 

 

 

 

 

 

 

2012

 

Collar

 

467,736

 

$

 90.00

 

$

 106.05

 

$

 3,245,731

 

 

 

Swap

 

177,380

 

85.22

 

85.22

 

(165,762

)

2013

 

Collar

 

410,616

 

92.10

 

108.91

 

3,673,068

 

 

 

Swap

 

195,417

 

81.72

 

81.72

 

(1,461,368

)

Gas

 

 

 

 

 

 

 

 

 

 

 

2012

 

Swap

 

99,748

 

6.75

 

6.75

 

377,896

 

2013

 

Swap

 

154,806

 

6.40

 

6.40

 

442,894

 

 

 

 

 

 

 

 

 

 

 

$

 6,112,459

 

 

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 June 30, 2012.  The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that

 

20



 

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 June 30, 2012, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at the reasonable assurance level.

 

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

 

Changes in Internal Control over Financial Reporting

 

There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended June 30, 2012 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

PART II—OTHER INFORMATION

 

Item 1.    Legal Proceedings.

 

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

 

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

 

In July 2011, our board of directors formed a Special Litigation Committee comprised of three non-executive directors to conduct an investigation of the allegations. The Special Litigation Committee retained outside independent advisors and conducted an in-depth investigation. The Special Litigation Committee concluded that neither it nor its legal or financial advisors had found any evidence to support any of Mr. Bennett’s allegations. Our board of directors concluded that the allegations against Mr. Starzer are unsubstantiated and lack merit. However, there can be no assurance as to the ultimate outcome of the arbitration proceedings. The arbitration proceedings commenced in July 2012 and it is not clear when a final decision will be rendered.  Mr. Starzer plans to continue to vigorously defend against Mr. Bennett’s claims.

 

See Part I, Item 1, Note 7 to our unaudited condensed consolidated financial statements entitled “Commitment and Contingent Liabilities,” which is incorporated herein by reference.

 

Item 1A. Risk Factors.

 

Our business faces many risks.  Any of the risk factors discussed in this Report, Item 1A of our 2011 Annual Report or our other SEC filings could have a material impact on our business, financial position or results of operations.  Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operation.  During the three months ended June 30, 2012, there has been no material change to such risk factors.

 

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

 

None.

 

Item 3.    Defaults Upon Senior Securities.

 

None.

 

21



 

Item 4.    Mine Safety Disclosures.

 

Not applicable.

 

Item 5.    Other Information.

 

None.

 

Item 6.    Exhibits.

 

Exhibit
No.

 

Description of Exhibit

 

 

 

10.1

 

Resignation, Consent and Appointment Agreement and Amendment Agreement, date as of April 6, 2012, by and among BNP Paribas, in its capacity as Administrative Agent and Issuing Lender, and the other parties thereto (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the three months ended March 31, 2012 filed on May 11, 2012)

 

 

 

10.2

 

Amendment No. 3 & Agreement, dated as of May 8, 2012, to the Credit Agreement among Bonanza Creek Energy, Inc., KeyBank National Association, as Administrative Agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the three months ended March 31, 2012 filed on May 11, 2012)

 

 

 

10.3

 

From of Restricted Stock Agreement (Employee) under the 2011 Bonanza Creek Energy, Inc. Long Term Incentive Plan

 

 

 

10.4

 

Form of Restricted Stock Agreement (Director) under the 2011 Bonanza Creek Energy, Inc. Long Term Incentive Plan

 

 

 

10.5

 

Amendment No. 4, dated as of July 31, to the Credit Agreement among Bonanza Creek Energy, Inc., Key Bank National Association, as Administrative Agent, and the lenders party thereto

 

 

 

31.1

 

Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)

 

 

 

31.2

 

Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)

 

 

 

32.1

 

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

 

 

 

32.2

 

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

 

 

 

101

 

The following materials from the Bonanza Creek Energy, Inc. Quarterly Report on Form 10-Q for the quarter ended June 30, 2012, formatted in XBRL (Extensible Business Reporting Language) include (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Stockholders’ Equity, (iv) the Condensed Consolidated Statements of Cash Flows and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text. The information in Exhibit 101 is “furnished” and not “filed”, as provided in Rule 402 of Regulation S-T.

 

22



 

SIGNATURES

 

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

 

 

 

 

BONANZA CREEK ENERGY, INC.

 

 

 

 

 

Date:

August 13, 2012

 

By:

/s/ MICHAEL R. STARZER

 

 

 

Michael R. Starzer

 

 

 

President and Chief Executive Officer

 

 

 

(principal executive officer)

 

 

 

 

 

 

 

 

 

 

 

 

 

By:

/s/ JAMES R. CASPERSON

 

 

 

James R. Casperson

 

 

 

Executive Vice President and Chief Financial Officer

 

 

 

(principal financial officer)

 

23