Table of Contents

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

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

 

For the quarterly period ended June 30, 2014

 

Commission File Number:  001-35371

 

Bonanza Creek Energy, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware

 

61-1630631

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification No.)

 

 

 

410 17th Street, Suite 1400

 

 

Denver, Colorado

 

80202

(Address of principal executive offices)

 

(Zip Code)

 

(720) 440-6100

(Registrant’s telephone number, including area code)

 

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

 

Accelerated filer o

 

 

 

Non-accelerated filer o

 

Smaller reporting company o

(Do not check if a smaller reporting company)

 

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ¨ Yes  x No

 

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. As of August 4, 2014, the registrant had 41,263,812 shares of common stock outstanding.

 

 

 



Table of Contents

 

BONANZA CREEK ENERGY, INC.

INDEX

 

 

 

 

PAGE

Part I.

FINANCIAL INFORMATION

 

 

 

 

 

 

Item 1.

Financial Statements (Unaudited)

 

 

 

 

 

 

 

Condensed Consolidated Balance Sheets June 30, 2014, and December 31, 2013

3

 

 

 

 

 

 

Condensed Consolidated Statements of Operations Three and Six Months Ended June 30, 2014, and 2013

4

 

 

 

 

 

 

Condensed Consolidated Statements of Cash Flows Six Months Ended June 30, 2014, and 2013

5

 

 

 

 

 

 

Notes to Condensed Consolidated Financial Statements

6

 

 

 

 

 

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

15

 

 

 

 

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

25

 

 

 

 

 

Item 4.

Controls and Procedures

26

 

 

 

 

Part II.

OTHER INFORMATION

 

 

 

 

 

 

Item 1.

Legal Proceedings

26

 

 

 

 

 

Item 1A.

Risk Factors

26

 

 

 

 

 

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

27

 

 

 

 

 

Item 3.

Defaults Upon Senior Securities

27

 

 

 

 

 

Item 4.

Mine Safety Disclosures

27

 

 

 

 

 

Item 5.

Other Information

27

 

 

 

 

 

Item 6.

Exhibits

27

 

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Table of Contents

 

PART I - FINANCIAL INFORMATION

Item 1.   Financial Statements.

 

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

 

 

 

June 30, 2014

 

December 31, 2013

 

 

 

(in thousands, except share data)

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

36,555

 

$

180,582

 

Accounts receivable:

 

 

 

 

 

Oil and gas sales

 

80,644

 

57,485

 

Joint interest and other

 

22,141

 

12,915

 

Prepaid expenses and other

 

4,213

 

1,638

 

Inventory of oilfield equipment

 

8,613

 

10,696

 

Derivative asset

 

153

 

858

 

Total current assets

 

152,319

 

264,174

 

Property and equipment (successful efforts method), at cost:

 

 

 

 

 

Proved properties

 

1,576,118

 

1,257,288

 

Less: accumulated depreciation, depletion and amortization

 

(316,943

)

(224,848

)

Total proved properties, net

 

1,259,175

 

1,032,440

 

Unproved properties

 

14,654

 

45,081

 

Wells in progress

 

117,364

 

110,848

 

Natural gas plant, net of accumulated depreciation of $7,180 in 2014 and $5,903 in 2013

 

69,108

 

71,474

 

Other property and equipment, net of accumulated depreciation of $4,270 in 2014 and $2,822 in 2013

 

9,947

 

7,406

 

Oil and gas properties held for sale, net of accumulated depreciation, depletion, and amortization of $- in 2014 and $1,463 in 2013 (note 4)

 

 

360

 

Total property and equipment, net

 

1,470,248

 

1,267,609

 

Long-term derivative asset

 

 

293

 

Other noncurrent assets

 

24,548

 

13,859

 

Total assets

 

$

1,647,115

 

$

1,545,935

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable and accrued expenses (note 5)

 

$

160,503

 

$

121,665

 

Oil and gas revenue distribution payable

 

38,289

 

36,241

 

Contractual obligation for land acquisition

 

12,000

 

12,000

 

Derivative liability

 

25,745

 

5,320

 

Total current liabilities

 

236,537

 

175,226

 

Long-term liabilities:

 

 

 

 

 

Revolving credit facility

 

 

 

Senior Notes, net of unamortized premium of $8,233 in 2014 and $8,847 in 2013

 

508,233

 

508,847

 

Contractual obligation for land acquisition

 

22,414

 

22,033

 

Ad valorem taxes

 

19,058

 

18,867

 

Derivative liability

 

7,724

 

1,203

 

Deferred income taxes, net

 

161,776

 

152,681

 

Asset retirement obligations

 

11,273

 

11,050

 

Total liabilities

 

967,015

 

889,907

 

Commitments and contingencies (note 7)

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

Preferred stock, $.001 par value, 25,000,000 shares authorized, none outstanding

 

 

 

Common stock, $.001 par value, 225,000,000 shares authorized, 40,400,581 and 40,285,919 issued and outstanding in 2014 and 2013, respectively

 

40

 

40

 

Additional paid-in capital

 

537,135

 

527,752

 

Retained earnings

 

142,925

 

128,236

 

Total stockholders’ equity

 

680,100

 

656,028

 

Total liabilities and stockholders’ equity

 

$

1,647,115

 

$

1,545,935

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (UNAUDITED)

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

(in thousands, except per share amounts)

 

Operating net revenues:

 

 

 

 

 

 

 

 

 

Oil and gas sales

 

$

151,682

 

$

84,517

 

$

279,077

 

$

162,825

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Lease operating

 

18,018

 

12,898

 

35,099

 

24,029

 

Severance and ad valorem taxes

 

16,263

 

5,352

 

27,013

 

10,165

 

Exploration

 

96

 

862

 

1,179

 

1,424

 

Depreciation, depletion and amortization

 

54,117

 

29,517

 

95,248

 

52,880

 

General and administrative (including $7,353 $2,685, $14,150, and $7,063, respectively, of stock-based compensation)

 

24,547

 

13,283

 

48,261

 

26,449

 

Total operating expenses

 

113,041

 

61,912

 

206,800

 

114,947

 

Income from operations

 

38,641

 

22,605

 

72,277

 

47,878

 

Other income (expense):

 

 

 

 

 

 

 

 

 

Derivative gain (loss)

 

(27,307

)

7,562

 

(36,085

)

2,447

 

Interest expense

 

(9,434

)

(5,870

)

(18,769

)

(7,833

)

Other income (loss)

 

167

 

(86

)

216

 

50

 

Total other income (expense)

 

(36,574

)

1,606

 

(54,638

)

(5,336

)

Income from continuing operations before taxes

 

2,067

 

24,211

 

17,639

 

42,542

 

Income tax expense

 

(796

)

(9,328

)

(6,791

)

(16,386

)

Income from continuing operations

 

$

1,271

 

$

14,883

 

$

10,848

 

$

26,156

 

Discontinued operations (note 4):

 

 

 

 

 

 

 

 

 

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

 

 

(274

)

(85

)

(301

)

Gain (loss) on sale of oil and gas properties

 

(184

)

 

6,330

 

 

Income tax (expense) benefit

 

71

 

106

 

(2,404

)

116

 

Gain (loss) from discontinued operations

 

(113

)

(168

)

3,841

 

(185

)

Net income

 

$

1,158

 

$

14,715

 

$

14,689

 

$

25,971

 

Comprehensive income

 

$

1,158

 

$

14,715

 

$

14,689

 

$

25,971

 

Basic and diluted income per share:

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

$

0.03

 

$

0.37

 

$

0.27

 

$

0.65

 

Income (loss) from discontinued operations

 

$

 

$

(0.01

)

$

0.09

 

$

 

Net income per common share

 

$

0.03

 

$

0.36

 

$

0.36

 

$

0.65

 

Basic weighted-average common shares outstanding

 

39,758

 

39,336

 

39,656

 

39,295

 

Diluted weighted-average common shares outstanding

 

39,857

 

39,350

 

39,780

 

39,327

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

 

 

 

Six Months Ended June 30,

 

 

 

2014

 

2013

 

 

 

(in thousands)

 

Cash flows from operating activities:

 

 

 

 

 

Net income

 

$

14,689

 

$

25,971

 

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

 

 

 

 

 

Depreciation, depletion and amortization

 

95,316

 

53,085

 

Deferred income taxes

 

9,095

 

16,270

 

Stock-based compensation

 

14,150

 

7,063

 

Amortization of deferred financing costs

 

1,156

 

665

 

Amortization of premium on Senior Notes

 

(614

)

 

Accretion of contractual obligation for land acquisition

 

381

 

381

 

Derivative (gain) loss

 

36,085

 

(2,447

)

Gain on sale of oil and gas properties

 

(6,330

)

 

Other

 

(14

)

 

Changes in current assets and liabilities:

 

 

 

 

 

Accounts receivable

 

(32,385

)

(9,343

)

Prepaid expenses and other assets

 

(2,575

)

633

 

Accounts payable and accrued liabilities

 

29,114

 

(1,377

)

Settlement of asset retirement obligations

 

(99

)

(73

)

Net cash provided by operating activities

 

157,969

 

90,828

 

Cash flows from investing activities:

 

 

 

 

 

Acquisition of oil and gas properties

 

(3,091

)

(8,352

)

Proceeds from sale of oil and gas properties

 

6,000

 

 

Exploration and development of oil and gas properties

 

(275,890

)

(162,689

)

Natural gas plant capital expenditures

 

(271

)

(3,987

)

Derivative cash settlements

 

(8,142

)

(2,993

)

(Increase) decrease in restricted cash

 

(11,280

)

79

 

Additions to property and equipment - non oil and gas

 

(3,989

)

(2,626

)

Net cash used in investing activities

 

(296,663

)

(180,568

)

Cash flows from financing activities:

 

 

 

 

 

Proceeds from credit facility

 

 

33,500

 

Payments to credit facility

 

 

(191,500

)

Proceeds from sale of Senior Notes

 

 

300,000

 

Offering costs related to sale of senior subordinated notes

 

(277

)

(7,270

)

Payment of employee tax withholdings in exchange for return of common stock

 

(4,766

)

(3,127

)

Deferred financing costs

 

(290

)

(46

)

Net cash (used in) provided by financing activities

 

(5,333

)

131,557

 

Net change in cash and cash equivalents

 

(144,027

)

41,817

 

Cash and cash equivalents:

 

 

 

 

 

Beginning of period

 

180,582

 

4,268

 

End of period

 

$

36,555

 

$

46,085

 

Supplemental cash flow disclosure:

 

 

 

 

 

Cash paid for interest

 

$

17,857

 

$

2,321

 

Cash paid for income taxes

 

$

100

 

$

100

 

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

 

$

10,920

 

$

7,401

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

5



Table of Contents

 

BONANZA CREEK ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

NOTE 1 - ORGANIZATION AND BUSINESS

 

Bonanza Creek Energy, Inc. (the “Company” or “BCEI”) is engaged in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States. Our oil and liquids weighted assets are concentrated primarily in the Wattenberg Field in Colorado (Rocky Mountain region) and the Dorcheat Macedonia Field in Southern Arkansas (Mid-Continent region).

 

NOTE 2 - BASIS OF PRESENTATION

 

These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information. The quarterly financial statements included herein do not necessarily include all of the disclosures as may be required under generally accepted accounting principles for complete financial statements. There has been no material change in the information disclosed in the notes to the consolidated financial statements included in BCEI’s Annual Report on Form 10-K for the year ended December 31, 2013 (“2013 Form 10-K”), except as disclosed herein. These consolidated financial statements include all of the adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and results of operations. All such adjustments are of a normal recurring nature only. The results of operations for the quarterly periods are not necessarily indicative of the results to be expected for the full fiscal year. The Company evaluated events subsequent to the balance sheet date of June 30, 2014, through the filing date of this report. Certain prior period amounts are reclassified to conform to the current period presentation, when necessary.

 

Principles of Consolidation

 

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

 

Significant Accounting Policies

 

The significant accounting policies followed by the Company were set forth in Note 1 to the 2013 Form 10-K and are supplemented by the notes throughout in this report. These unaudited condensed consolidated financial statements should be read in conjunction with the 2013 Form 10-K.

 

Recently Issued Accounting Standards

 

In April 2014, the Financial Accounting Standards Board issued Update No. 2014-08 — Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The update is aimed at reducing the frequency of disposals reported as discontinued operations by focusing on strategic shifts that have or will have a major effect on an entity’s operations and financial results. This authoritative accounting guidance is effective for interim and annual periods beginning after December 15, 2014 and is to be applied prospectively. The Company is currently evaluating the provisions of this guidance and assessing its impact, but does not currently believe it will have a material effect on the Company’s financial statements or disclosures.

 

In May 2014, the FASB issued Update No. 2014-09 — Revenue From Contracts With Customers. The update prescribes two acceptable methods and is effective for the annual period beginning after December 15, 2016, including interim periods within that reporting period. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

 

In June 2014, the FASB issued Update No. 2014-12, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved after the Requisite Service Period. The guidance relates to the recognition of share-based compensation when an award provides that a performance target can be achieved after the requisite service period. This authoritative accounting guidance may be applied either prospectively or retrospectively and is effective for annual periods and interim periods beginning after December 15, 2015. The Company is currently evaluating the provisions of this guidance and assessing its impact on the Company’s financial statements and disclosures.

 

NOTE 3 - ACQUISITIONS

 

Subsequent to June 30, 2014, the Company acquired approximately 86,000 gross (34,000 net) acres of oil and gas properties, leasehold mineral interests and related assets located in the Wattenberg Field (“Wattenberg Field Acquisition”) from a private operator. The Company paid $174.2 million in cash and issued 853,492 shares of the Company’s common stock valued at $57.47 per share, the market price at the time of closing, for the acquired assets. Proved developed reserve estimates on the acquired properties at the time of closing will not be material. The Wattenberg Field Acquisition had an effective date of June 1, 2014 and closed on July 8, 2014. The Company made an $11,280,000 escrow deposit on May 21, 2014, which is reflected under noncurrent assets within the accompanying condensed consolidated balance sheets (“accompanying balance sheets”) and within the investing section in the accompanying condensed consolidated statements of cash flows (“accompanying statements of cash flows”) for the six month period ended June 30, 2014. The amounts held in escrow were paid to the seller at closing.

 

In connection with the Wattenberg Field Acquisition, the Company entered into a Registration Rights Agreement with respect to the shares of common stock issued at closing. Pursuant to the Registration Rights Agreement, and subject to certain terms

 

6



Table of Contents

 

and conditions, the Company filed a registration statement with the Securities and Exchange Commission (“SEC”) registering the resale from time to time of the shares of common stock issued to the seller at closing.

 

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, $12 million in July 2013 and $12 million in July 2014. The Company will pay approximately $12 million in July 2015 and July 2016. The future payments were discounted based on our effective borrowing rate to arrive at a purchase price of $57 million. Future payments include imputed interest and are secured by a letter of credit. The letter of credit as of June 30, 2014 and on the filing date of this report was $36 million and $24 million, respectively.

 

NOTE 4 - DISCONTINUED OPERATIONS

 

During June of 2012, the Company began marketing, with intent to sell, all of its oil and gas properties in California classifying them as assets held for sale. Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. The Company determined that its intent to sell all of its assets in a region qualified as discontinued operations. The Company sold its remaining property during the first quarter of 2014 for approximately $6.0 million and recorded a gain on the sale of oil and gas properties in the amount of $6.3 million. The carrying amounts of the remaining properties included within assets held for sale classified as discontinued operations are presented below.

 

 

 

As of June 30,
2014

 

As of December
31, 2013

 

 

 

(in thousands)

 

Oil and gas properties, successful efforts method:

 

 

 

 

 

Proved properties

 

$

 

$

1,721

 

Unproved properties

 

 

1

 

Wells in progress

 

 

101

 

Total property and equipment

 

 

1,823

 

Less accumulated depreciation, depletion and amortization

 

 

(1,463

)

Property and equipment, net

 

$

 

$

360

 

 

The total revenues, expenses, and income associated with the operation of the oil and gas properties held for sale are presented below.

 

 

 

Three Months Ended June 30

 

Six Months Ended June 30

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

(in thousands)

 

Net revenues:

 

 

 

 

 

 

 

 

 

Oil and gas sales

 

$

 

$

437

 

$

361

 

$

875

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Lease operating

 

 

602

 

366

 

905

 

Severance and ad valorem taxes

 

 

1

 

12

 

1

 

Exploration

 

 

8

 

 

65

 

Depreciation, depletion and amortization

 

 

100

 

68

 

205

 

Total operating expenses

 

 

711

 

446

 

1,176

 

 

 

 

 

 

 

 

 

 

 

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

 

$

 

$

(274

)

$

(85

)

$

(301

)

 

NOTE 5 - ACCOUNTS PAYABLE AND ACCRUED EXPENSES

 

Accounts payable and accrued expenses contain the following:

 

 

 

As of June 30,
 2014

 

As of December 31,
2013

 

 

 

(in thousands)

 

Drilling and completion costs

 

$

91,891

 

$

 

80,971

 

Accounts payable trade

 

27,127

 

3,288

 

Accrued general and administrative cost

 

11,150

 

12,720

 

Lease operating expenses

 

3,833

 

5,440

 

Accrued reclamation cost

 

162

 

168

 

Accrued interest

 

7,054

 

7,065

 

Accrued oil and gas derivatives

 

2,665

 

446

 

Production and ad valorem taxes and other

 

16,621

 

11,567

 

Total accounts payable and accrued expenses

 

$

160,503

 

$

 

121,665

 

 

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NOTE 6 — LONG-TERM DEBT

 

The Company’s senior secured revolving Credit Agreement (the “Revolver” or “credit facility”), dated March 29, 2011, as amended, was further amended on May 14, 2014 to increase the credit facility amount from $600 million to $1 billion, to increase the borrowing base from $450 million to $525 million, and to reduce the effective interest rate on future borrowings under the credit facility by 0.25%. The Company elected to limit bank commitments to $400 million while reserving the option to access, at the Company’s request, the full borrowing base prior to the next semi-annual redetermination on November 15, 2014. The Revolver is collateralized by substantially all the Company’s assets and matures on September 15, 2018. As of June 30, 2014 and December 31, 2013, the Company had no outstanding balance under the Revolver with an available borrowing capacity of $489 million and $414 million, respectively, after the reduction of the outstanding letter of credit of $36 million.

 

The Revolver 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 minimum current and debt coverage ratios. The Company was in compliance with all financial and non-financial covenants as of June 30, 2014 and through the filing date of this report.

 

NOTE 7 - COMMITMENTS AND CONTINGENT LIABILITIES

 

From time to time, the Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. The Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its consolidated financial statements. In accordance with accounting authoritative guidance, an accrual is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, the Company may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. The Company regularly reviews contingencies to determine the adequacy of its accruals and related disclosures. No claims have been made, nor is the Company aware of any material uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration or the violation of any rules or regulations. As of the date of this filing, there were no material pending or overtly threatened legal actions against the Company of which it is aware.

 

Commitments

 

There have been no material changes from the commitments disclosed in the 2013 Form 10-K.

 

NOTE 8 — STOCK-BASED COMPENSATION

 

Restricted Stock under the Long Term Incentive Plan

 

The Company grants shares of restricted stock, which represents one share of the Company’s common stock vesting in one-third increments over three years. Shares of restricted stock are valued at the closing price of the Company’s common stock on the grant date and are recognized as general and administrative expense over the vesting period of the award.

 

During the six months ended June 30, 2014, the Company granted 219,079 shares of restricted stock under the Company’s Long Term Incentive Program (“LTIP”) to certain employees. The fair value of the issuance was $10.5 million. Total expense recorded for restricted stock for the three month periods ended June 30, 2014 and 2013, was $6.7 million and $2.5 million, respectively, and $13.2 million and $6.8 million for the six months ended June 30, 2014 and 2013, respectively. As of June 30, 2014, unrecognized compensation cost was $19.3 million and will be amortized through 2017.

 

During the six months ended June 30, 2014, the Company issued 9,416 shares of restricted common stock under the LTIP to its non-employee directors. Total expense recorded for non-employee directors for the three month periods ended June 30, 2014 and

 

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2013, was $297,000 and $80,000, respectively and $377,000 and $160,000 for the six months ended June 30, 2014 and 2013, respectively. These awards vest approximately one year after issuance.

 

A summary of the status and activity of non-vested restricted stock for the six months ended June 30, 2014 is presented below:

 

 

 

Restricted 
Stock

 

Weighted-
Average 
Grant-Date 
Fair Value

 

Non-vested at beginning of year

 

836,002

 

$

25.11

 

Granted

 

228,495

 

$

48.44

 

Vested

 

(431,893

)

$

25.81

 

Forfeited

 

(13,284

)

$

32.49

 

Non-vested at end of quarter

 

619,320

 

$

34.36

 

 

Performance Stock Units under the Long Term Incentive Plan

 

The Company grants performance stock units (“PSUs”) to certain officers of the Company. The number of shares of the Company’s common stock that may be issued to settle PSUs range from zero to two times the number of PSUs awarded and is determined based on the Company’s performance over a three-year measurement period. The PSUs granted during 2013 vest in their entirety at the end of the measurement period. The PSUs granted during 2014 vest at the end of each annual measurement period during the performance cycle up to two-thirds of the target number of PSUs that are eligible for vesting (such that an amount equal to 200% of the target number may be earned during the performance cycle of three years). The PSUs will be settled in shares following the end of the three-year performance cycle.

 

During the six months ended June 30, 2014, the Company granted 63,766 shares of PSUs under the LTIP to certain employees. The fair value of the issuance was $2.7 million. Total expense recorded for PSUs for the three month periods ended June 30, 2014 and 2013 was $392,000 and $103,000, respectively and $567,000 and $107,000 for the six month periods ended June 30, 2014 and 2013, respectively. As of June 30, 2014, there was $3.4 million of total unrecognized compensation expense related to unvested PSUs to be amortized through 2016.

 

A summary of the status and activity of PSUs for the six months ended June 30, 2014 is presented below:

 

 

 

PSU

 

Weighted-Average 
Grant-Date Fair Value

 

Non-vested at beginning of year (1)

 

40,191

 

$

32.05

 

Granted(1)

 

63,766

 

$

42.50

 

Vested(1)

 

 

$

 

Forfeited(1)

 

 

$

 

Non-vested at end of quarter(1)

 

103,957

 

$

38.46

 

 


(1)         The number of awards assumes that the associated performance condition is met at the target amount. The final number of shares of common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the performance condition.

 

NOTE 9 - FAIR VALUE MEASUREMENTS

 

The Company follows fair value measurement authoritative guidance for all assets and liabilities measured at fair value, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A hierarchy for inputs is used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. 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

 

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Level 2:                            Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations whose inputs are observable or whose significant value drivers are observable

 

Level 3:                            Significant inputs to the valuation model are unobservable

 

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

 

The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014 and December 31, 2013 and their classification within the fair value hierarchy:

 

 

 

As of June 30, 2014

 

 

 

Level 1

 

Level 2

 

Level 3

 

 

 

(in thousands)

 

Derivative assets

 

$

 

$

 

$

153

 

Derivative liabilities

 

$

 

$

12,171

 

$

21,298

 

 

 

 

As of December 31, 2013

 

 

 

Level 1

 

Level 2

 

Level 3

 

 

 

(in thousands)

 

Derivative assets

 

$

 

$

736

 

$

415

 

Derivative liabilities

 

$

 

$

1,741

 

$

4,782

 

 

Derivatives

 

Fair value of all derivative instruments are estimated with industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. All valuations were compared against counterparty statements to verify the reasonableness of the estimate. The Company’s commodity swaps are validated by 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. Presently, all of our derivative arrangements are concentrated with five counterparties all of which are lenders under the Company’s Revolver.

 

The following table reflects the activity for the commodity derivatives measured at fair value using Level 3 inputs for the three month periods ended June 30, 2014 and 2013.

 

 

 

For the Three Months Ended 
June 30, 2014

 

For the Three Months Ended 
June 30, 2013

 

 

 

Derivative 
Asset

 

Derivative 
Liability

 

Derivative 
Asset

 

Derivative 
Liability

 

 

 

(in thousands)

 

Beginning balance

 

$

145

 

$

8,162

 

$

981

 

2,347

 

Net increase (decrease) in fair value (1)

 

(1,350

)

11,221

 

1,556

 

(2,039

)

Net settlements (1)

 

1,358

 

(2,012

)

 

9

 

New derivatives

 

 

3,927

 

1,808

 

 

Transfers in (out) of Level 3

 

 

 

 

 

Ending balance

 

$

153

 

$

21,298

 

$

4,345

 

317

 

 


(1)         Net increase (decrease) in fair value and net settlements are a component of the derivative gain (loss) line item in the accompanying condensed consolidated statements of operations (“accompanying statements of operations”). Cash outflows for a derivative asset are shown as a positive number and a negative number for a derivative liability.

 

The following table reflects the activity for the commodity derivatives measured at fair value using Level 3 inputs for the six month periods ended June 30, 2014 and 2013.

 

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Table of Contents

 

 

 

For the Six Months Ended 
June 30, 2014

 

For the Six Months Ended 
June 30, 2013

 

 

 

Derivative 
Asset

 

Derivative 
Liability

 

Derivative 
Asset

 

Derivative 
Liability

 

 

 

(in thousands)

 

Beginning balance

 

$

415

 

$

4,782

 

$

1,727

 

1,235

 

Net increase (decrease) in fair value (1)

 

(2,553

)

14,995

 

(465

)

(1,970

)

Net settlements (1)

 

2,237

 

(2,894

)

 

10

 

New derivatives

 

54

 

4,415

 

3,083

 

1,042

 

Transfers in (out) of Level 3

 

 

 

 

 

Ending balance

 

$

153

 

$

21,298

 

$

4,345

 

317

 

 


(1)         Net increase (decrease) in fair value and net settlements are a component of the derivative gain (loss) line item in the accompanying statements of operations. Cash outflows for a derivative asset are shown as a positive number and a negative number for a derivative liability.

 

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%. 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 the NYMEX strip pricing, adjusted for basis differentials. Future operating costs are also adjusted as deemed appropriate for these estimates. Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. There were no proved properties measured at fair value at June 30, 2014 or December 31, 2013.

 

Unproved Oil and Gas Properties

 

Unproved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. To measure the fair value of unproved properties, the Company uses Level 3 inputs and the income valuation technique, which takes into account the following significant assumptions: future development plans, risk weighted potential resource recovery, and estimated reserve values. Unproved properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by the most current bid prices received from third parties. If an estimated selling price is not available, the Company uses the price received for similar acreage in recent transactions by the Company or other market participants in the principal market. There were no unproved properties measured at fair value as of June 30, 2014 or December 31, 2013.

 

Asset Retirement Obligation

 

The Company utilizes the income valuation technique to determine the fair value of the asset retirement obligation liability at the point of inception by applying a credit-adjusted risk-free rate, which takes into account the Company’s credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Upon completion of wells and natural gas plants, the Company records an asset retirement obligation at fair value using Level 3 assumptions. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.  There were no asset retirement obligations measured at fair value at June 30, 2014 or December 31, 2013.

 

Long-term Debt

 

As of June 30, 2014, the Company had $500 million of outstanding 6.75% Senior Notes (the “6.75 % Senior Notes”).  The 6.75% Senior Notes are recorded at cost net of the unamortized premium on the accompanying balance sheets at $508.2 million and $508.8 million as of June 30, 2014 and December 31, 2013, respectively. The fair value of the Senior Notes as of June 30, 2014 and

 

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Table of Contents

 

December 31, 2013 was $537.5 million and $527.5 million, respectively, measured using Level 1 inputs based on a secondary market trading price. The Company’s credit facility, when drawn upon, approximates fair value, as the applicable interest rates are floating.

 

NOTE 10 — DERIVATIVES

 

The Company enters into commodity derivative contracts to mitigate a portion of its exposure to potentially adverse market changes in commodity prices and the associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The Company’s derivatives include swaps and collar arrangements for oil and gas and none of the derivative instruments qualify as having hedging relationships.

 

As of June 30, 2014, and as of the filing date of this report, the Company had the following derivative commodity contracts in place:

 

Settlement 
Period

 

Derivative
Instrument

 

Total Volumes
(Bbls/MMBtu 
per day)

 

Average 
Fixed 
Price

 

Average 
Short Floor 
Price

 

Average
Floor
Price

 

Average
Ceiling
Price

 

Fair Market
Value of Asset
(Liability)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(in thousands)

 

Oil

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3Q 2014

 

Swap

 

5,870

 

$

96.09

 

 

 

 

 

 

 

$

(4,452

)

4Q 2014

 

Swap

 

6,370

 

$

95.62

 

 

 

 

 

 

 

(3,624

)

1Q 2015

 

Swap

 

6,000

 

$

95.39

 

 

 

 

 

 

 

(2,204

)

2Q 2015

 

Swap

 

5,000

 

$

94.21

 

 

 

 

 

 

 

(1,335

)

3Q 2015

 

Swap

 

2,000

 

$

93.43

 

 

 

 

 

 

 

(394

)

4Q 2015

 

Swap

 

2,000

 

$

93.43

 

 

 

 

 

 

 

(162

)

3Q 2014

 

Collar

 

4,326

 

 

 

 

 

$

86.16

 

$

96.57

 

(3,179

)

4Q 2014

 

Collar

 

4,326

 

 

 

 

 

$

86.16

 

$

96.57

 

(2,602

)

3Q 2014

 

3-Way Collar

 

2,000

 

 

 

$

65.00

 

$

87.68

 

$

99.75

 

(941

)

4Q 2014

 

3-Way Collar

 

2,000

 

 

 

$

65.00

 

$

87.68

 

$

99.75

 

(791

)

1Q 2015

 

3-Way Collar

 

6,500

 

 

 

$

68.08

 

$

84.32

 

$

95.90

 

(3,552

)

2Q 2015

 

3-Way Collar

 

5,500

 

 

 

$

67.73

 

$

84.09

 

$

95.16

 

(2,672

)

3Q 2015

 

3-Way Collar

 

6,500

 

 

 

$

68.46

 

$

84.62

 

$

95.49

 

(2,438

)

4Q 2015

 

3-Way Collar

 

6,500

 

 

 

$

68.46

 

$

84.62

 

$

95.49

 

(2,002

)

1Q 2016

 

3-Way Collar

 

5,500

 

 

 

$

70.00

 

$

85.00

 

$

96.83

 

(983

)

2Q 2016

 

3-Way Collar

 

5,500

 

 

 

$

70.00

 

$

85.00

 

$

96.83

 

(710

)

3Q 2016

 

3-Way Collar

 

5,500

 

 

 

$

70.00

 

$

85.00

 

$

96.83

 

(546

)

4Q 2016

 

3-Way Collar

 

5,500

 

 

 

$

70.00

 

$

85.00

 

$

96.83

 

(496

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(33,083

)

Gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3Q 2014

 

3-Way Collar

 

30,000

 

 

 

$

3.63

 

$

4.21

 

$

4.81

 

$

57

 

4Q 2014

 

3-Way Collar

 

30,000

 

 

 

$

3.63

 

$

4.21

 

$

4.81

 

(95

)

1Q 2015

 

3-Way Collar

 

15,000

 

 

 

$

3.50

 

$

4.00

 

$

4.75

 

(290

)

2Q 2015

 

3-Way Collar

 

15,000

 

 

 

$

3.50

 

$

4.00

 

$

4.75

 

88

 

3Q 2015

 

3-Way Collar

 

15,000

 

 

 

$

3.50

 

$

4.00

 

$

4.75

 

52

 

4Q 2015

 

3-Way Collar

 

15,000

 

 

 

$

3.50

 

$

4.00

 

$

4.75

 

(45

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(233

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

$

(33,316

)

 

Derivative Assets and Liabilities Fair Value

 

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

 

The following table contains a summary of all the Company’s derivative positions reported on the accompanying balance sheets as of June 30, 2014 and December 31, 2013:

 

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Table of Contents

 

 

 

As of June 30, 2014

 

 

 

Balance Sheet Location

 

Fair Value

 

 

 

 

 

(in thousands)

 

Derivative Assets:

 

 

 

 

 

Commodity contracts

 

Current assets

 

$

153

 

Commodity contracts

 

Noncurrent assets

 

 

Derivative Liabilities:

 

 

 

 

 

Commodity contracts

 

Current liabilities

 

(25,745

)

Commodity contracts

 

Long-term liabilities

 

(7,724

)

Total net derivative liability

 

 

 

$

(33,316

)

 

 

 

As of December 31, 2013

 

 

 

Balance Sheet Location

 

Fair Value

 

 

 

 

 

(in thousands)

 

Derivative Assets:

 

 

 

 

 

Commodity contracts

 

Current assets

 

$

858

 

Commodity contracts

 

Noncurrent assets

 

293

 

Derivative Liabilities:

 

 

 

 

 

Commodity contracts

 

Current liabilities

 

(5,320

)

Commodity contracts

 

Long-term liabilities

 

(1,203

)

Total net derivative liability

 

 

 

$

(5,372

)

 

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

 

 

 

For the Three Months 
Ended June 30,

 

For the Six Months Ended
June 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

(in thousands, except per share amounts)

 

Derivative cash settlement gain (loss):

 

 

 

 

 

 

 

 

 

Oil contracts

 

$

(5,894

)

$

(1,593

)

$

(7,594

)

$

(3,244

)

Gas contracts

 

(21

)

107

 

(548

)

251

 

Total derivative cash settlement (loss)(1)

 

$

(5,915

)

$

(1,486

)

$

(8,142

)

$

(2,993

)

 

 

 

 

 

 

 

 

 

 

Change in fair value gain (loss)

 

 

 

 

 

 

 

 

 

Oil contracts

 

$

(21,724

)

$

9,048

 

$

(27,717

)

$

5,440

 

Gas contracts

 

332

 

 

(226

)

 

Total change in fair value gain (loss)

 

$

(21,392

)

$

9,048

 

$

(27,943

)

$

5,440

 

 

 

 

 

 

 

 

 

 

 

Total derivative gain (loss)(2)

 

$

(27,307

)

$

7,562

 

$

(36,085

)

$

2,447

 

 


(1)         Derivative cash settlement gain (loss) is reported in the derivative cash settlements line item on the accompanying statements of cash flows within the net cash used in investing activities.

 

(2)         Total derivative gain (loss) is reported in the derivative gain (loss) line item on the accompanying statements of cash flows within the net cash provided by operating activities.

 

NOTE 11 — EARNINGS PER SHARE

 

The Company issues shares of restricted stock entitling the holders to receive non-forfeitable dividends, if and when, the Company were to declare a dividend, before vesting, thus making the awards participating securities. The awards are included in the calculation of earnings per share under the two-class method. The two-class method allocates earnings for the period between common shareholders and unvested participating shareholders.

 

The Company issues PSUs, which represent the right to receive, upon settlement of the PSUs after completion of a three-year performance period, a number of shares of the Company’s common stock that range from 0% to 200% of the number of PSUs granted on the award date. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period applicable to such PSUs. Please refer to Note 8 — Stock-Based Compensation, for additional discussion.

 

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The following table sets forth the calculation of earnings per basic and diluted shares from continuing and discontinued operations for the three and six month periods ended June 30, 2014 and 2013:

 

 

 

For the Three Months 
Ended June 30,

 

For the Six Months 
Ended June 30,

 

 

 

2014

 

2013

 

2014

 

2013

 

 

 

(in thousands, except per share amounts)

 

Income from continuing operations:

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

$

1,271

 

$

14,883

 

$

10,848

 

$

26,156

 

Less: undistributed earnings to unvested restricted stock

 

23

 

379

 

205

 

614

 

Undistributed earnings to common shareholders

 

1,248

 

14,504

 

10,643

 

25,542

 

Basic income per common share from continuing operations

 

$

0.03

 

$

0.37

 

$

0.27

 

$

0.65

 

Diluted income per common share from continuing operations

 

$

0.03

 

$

0.37

 

$

0.27

 

$

0.65

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from discontinued operations:

 

 

 

 

 

 

 

 

 

Income (loss) from discontinued operations

 

$

(113

)

$

(168

)

$

3,841

 

$

(185

)

Less: undistributed earnings to unvested restricted stock

 

2

 

4

 

73

 

4

 

Undistributed earnings (loss) to common shareholders

 

(111

)

(164

)

3,768

 

(181

)

Basic income (loss) per common share from discontinued operations

 

$

 

$

(0.01

)

$

0.09

 

$

 

Diluted income (loss) per common share from discontinued operations

 

$

 

$

(0.01

)

$

0.09

 

$

 

 

 

 

 

 

 

 

 

 

 

Net income:

 

 

 

 

 

 

 

 

 

Net income

 

$

1,158

 

$

14,715

 

$

14,689

 

$

25,971

 

Less: undistributed earnings to unvested restricted stock

 

21

 

375

 

277

 

610

 

Undistributed earnings to common shareholders

 

1,137

 

14,340

 

14,412

 

25,361

 

Basic net income per common share

 

$

0.03

 

$

0.36

 

$

0.36

 

$

0.65

 

Diluted net income per common share

 

$

0.03

 

$

0.36

 

$

0.36

 

$

0.65

 

 

 

 

 

 

 

 

 

 

 

Weighted-average shares outstanding - basic

 

39,758,489

 

39,335,688

 

39,655,968

 

39,294,942

 

Add: dilutive effect of contingent PSUs

 

98,539

 

14,556

 

124,227

 

32,187

 

Weighted-average shares outstanding - diluted

 

39,857,028

 

39,350,244

 

39,780,195

 

39,327,129

 

 

The Company had no anti-dilutive shares for the three and six month periods ended June 30, 2014 and 2013.

 

NOTE 12 - INCOME TAXES

 

The Company uses the asset and liability method of accounting for deferred income taxes. Deferred tax assets and liabilities are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities. Deferred tax assets or liabilities at the end of each period are determined using the tax rate in effect at that time. During the three and six month periods ended June 30, 2014 and 2013 the effective tax rate was 38.5%.

 

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

 

The Company has not taken any uncertain tax positions and has no valuation allowances.

 

NOTE 13 — SUBSEQUENT EVENT

 

On July 15, 2014, the Company issued $300 million aggregate principal amount of 5.75% Senior Notes (the “5.75% Senior Notes”) that mature on February 1, 2023. Interest on the 5.75% Senior Notes began accruing on July 15, 2014, and the Company will pay interest on February 1 and August 1 of each year, beginning on February 1, 2015. The 5.75% Senior Notes are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Revolver. The net proceeds from the sale of the 5.75% Senior Notes were $293.7 million after deductions of

 

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$6.3 million of expenses and underwriting discounts and commissions. The net proceeds were used to pay off the Company’s outstanding credit facility balance, that existed after June 30, 2014, and the Company will use the remainder for general corporate purposes, which may include funding its drilling and development program and other capital expenditures.

 

At any time prior to August 1, 2017, the Company may redeem up to 35% of the aggregate principal amount of the 5.75% Senior Notes at a redemption price of 105.75% of the principal amount, plus accrued and unpaid interest, with an amount of cash not greater than the net cash proceeds of an equity offering. The Company may redeem all or a part of the 5.75% Senior Notes at any time prior to August 1, 2018 subject to a “make-whole” premium and accrued and unpaid interest. On or after August 1, 2018, the Company may redeem all or a part of the 5.75% Senior Notes at the redemption price of 102.875% for 2018, 101.438% for 2019, and 100.0% for 2020 and thereafter, during the twelve month period beginning on August 1 of each applicable year, plus accrued and unpaid interest.

 

As of June 30, 2014, and through the filing date of this report, all of the existing subsidiaries of the Company are guarantors of the 5.75% Senior Notes, and all such subsidiaries are 100% owned by the Company. The guarantees by the subsidiaries are full and unconditional (except for customary release provisions) and constitute joint and several obligations of the subsidiaries. The Company has no independent assets or operations unrelated to its investments in its consolidated subsidiaries. There are no significant restrictions on the Company’s ability or the ability of any subsidiary guarantor to obtain funds from its subsidiaries by such means as a dividend or loan.

 

The Company’s Revolver’s borrowing base was decreased to $450 million from $525 million upon the issuance of the 5.75% Senior Notes. As of the date of this filing, the Company had no outstanding balance under the Revolver with an available borrowing capacity of $426 million, after the reduction of the outstanding letter of credit of $24 million and the reduction in the borrowing base from the issuance of the 5.75% Senior Notes.

 

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, 2013 (“2013 Form 10-K”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q (this “Report”).

 

Executive Summary

 

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

 

Despite the uncertainty surrounding the global economy and volatility in commodity prices, we believe the economic returns and organic growth generated by our portfolio of oil and gas assets positions us well moving forward. Our operations are focused in the Wattenberg Field in Colorado (Rocky Mountain region) and the Dorcheat Macedonia Field in Southern Arkansas (Mid-Continent region). The low risk, oil-weighted production profile of our Arkansas assets provides a strong cash flow base from which to develop our Wattenberg Field assets, principally the Niobrara and Codell formations in Colorado. Our corporate strategy is to create shareholder value by increasing production in our current assets, while opportunistically seeking strategic acquisitions in our core areas or other high return basins across the United States where we can apply our technical competencies of horizontal drilling and fracture stimulation. We maintain a high working interest in our properties, which allows us to control the pace and magnitude of our capital spending program.

 

Financial and Operating Highlights

 

Our financial results and operational highlights for the second quarter of 2014 included:

 

·            Net income of $1.2 million (including approximately $1.3 million from continuing operations), as compared with $14.7 million (including approximately $14.9 million from continuing operations) for the second quarter of 2013. The decrease in net income is primarily due to derivative losses and compensation paid in connection with executive departures;

 

·            Total liquidity of $525.6 million, consisting of a period-end cash balance plus funds available under our credit facility, as compared with $328.1 million for the second quarter of 2013;

 

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·            Entering into a purchase and sale agreement to acquire approximately 86,000 (34,000 net) acres, leasehold mineral interests and related assets within the Wattenberg Field for $223.3 million to increase our acreage position within the region and leverage current infrastructure and operational expertise. The acquisition closed during the third quarter of 2014;

 

·            Borrowing base increase under the Revolver of $75 million to $525 million during the second quarter of 2014;

 

·            Increased production by 69% to 2,079.3 MBoe in the second quarter of 2014 from 1,227.8 MBoe in the second quarter of 2013, with oil and NGL production representing 70% of total production; and

 

·            Drilled and completed 38 gross (31.9 net) productive wells within our Rocky Mountain region and 15 gross (10.8 net) productive wells within our Mid-Continent region during the second quarter of 2014.

 

During the six months ended June 30, 2014, we had the following financial and operational results:

 

·                  Cash flows provided by operating activities of $158.0 million, as compared with $90.8 million for the first half of 2013; and

 

·                  Capital expenditures of $293.6 million, as compared with $177.4 million for the first half of 2013.

 

Outlook for 2014

 

Because the global economic outlook and commodity price environment are uncertain, we have planned a flexible capital spending program. We estimate our total capital expenditures for 2014 to be between approximately $575 million to $625 million, allocated approximately 87% to the horizontal development of the Niobrara and Codell formations in the Wattenberg Field and 13% to the vertical development of the Dorcheat Macedonia and McKamie Patton Fields in Southern Arkansas. Actual capital expenditures may fluctuate materially based on, among other things, market conditions, the success of our drilling results as the year continues to progress and changes in the borrowing base under the Revolver. This capital investment is expected to produce average production volumes of 23,000 Boe/d to 25,000 Boe/d in 2014, while maintaining a strong oil and liquids profile.

 

Results for Continuing Operations

 

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

 

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

 

 

 

Three Months Ended June 30,

 

 

 

2014

 

2013

 

Change

 

Percent
Change

 

 

 

(In thousands, except percentages)

 

Revenues:

 

 

 

 

 

 

 

 

 

Crude oil sales

 

$

127,444

 

$

71,172

 

$

56,272

 

79

%

Natural gas sales

 

19,734

 

9,448

 

10,286

 

109

%

Natural gas liquids sales

 

4,504

 

3,893

 

611

 

16

%

CO2 sales

 

 

4

 

(4

)

(100

)%

Product revenue

 

$

151,682

 

$

84,517

 

$

67,165

 

79

%

 

 

 

 

 

 

 

 

 

 

Sales Volumes:

 

 

 

 

 

 

 

 

 

Crude oil (MBbls)

 

1,376.3

 

796.0

 

580.3

 

73

%

Natural gas (MMcf)

 

3,697.1

 

2,114.4

 

1,582.7

 

75

%

Natural gas liquids (MBbls)

 

86.8

 

79.4

 

7.4

 

9

%

Crude oil equivalent (MBoe)(1)

 

2,079.3

 

1,227.8

 

851.5

 

69

%

 

 

 

 

 

 

 

 

 

 

Average Sales Prices (before derivatives)(2)

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

92.60

 

$

89.41

 

$

3.19

 

4

%

Natural gas (per Mcf)

 

$

5.34

 

$

4.47

 

$

0.87

 

19

%

Natural gas liquids (per Bbl)

 

$

51.89

 

$

49.03

 

$

2.86

 

6

%

Crude oil equivalent (per Boe)(1)

 

$

72.95

 

$

68.83

 

$

4.12

 

6

%

 

 

 

 

 

 

 

 

 

 

Average Sales Prices (after derivatives)(2)

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

88.31

 

$

87.41

 

$

0.90

 

1

%

Natural gas (per Mcf)

 

$

5.33

 

$

4.52

 

$

0.81

 

18

%

Natural gas liquids (per Bbl)

 

$

51.89

 

$

49.03

 

$

2.86

 

6

%

Crude oil equivalent (per Boe)(1)

 

$

70.10

 

$

67.62

 

$

2.48

 

4

%

 

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

(2)  The derivatives economically hedge the price we receive for crude oil and natural gas.

 

Revenues increased by 79%, to $151.7 million for the three months ended June 30, 2014 compared to $84.5 million for the three months ended June 30, 2013 due to the increase in oil, natural gas, and natural gas liquids production of 73%, 75%, and 9%, respectively, for the comparable periods. The increased volumes are a direct result of the $269.7 million expended for drilling and completion during the last six months of 2013 and the $293.6 million expended during the six months ended June 30, 2014. During the period from June 30, 2013 through June 30, 2014, we drilled and completed 102 gross (91.8 net) wells in the Rocky Mountain region and 47 gross (36.2 net) wells in the Mid-Continent region. Our Wattenberg Field natural gas is sold as wet gas without processing into dry gas and NGLs, and therefore, sells at a premium due to its high BTU content.

 

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

 

 

 

Three Months Ended June 30,

 

 

 

2014

 

2013

 

Change

 

Percent
Change

 

 

 

(In thousands, except percentages)

 

Expenses:

 

 

 

 

 

 

 

 

 

Lease operating

 

$

18,018

 

$

12,898

 

$

5,120

 

40

%

Severance and ad valorem taxes

 

16,263

 

5,352

 

10,911

 

204

%

Exploration

 

96

 

862

 

(766

)

(89

)%

Depreciation, depletion and amortization

 

54,117

 

29,517

 

24,600

 

83

%

General and administrative

 

24,547

 

13,283

 

11,264

 

85

%

Operating expenses

 

$

113,041

 

$

61,912

 

$

51,129

 

83

%

 

 

 

 

 

 

 

 

 

 

Selected Costs ($ per Boe):

 

 

 

 

 

 

 

 

 

Lease operating

 

$

8.67

 

$

10.50

 

$

(1.83

)

(17

)%

Severance and ad valorem taxes

 

7.82

 

4.36

 

3.46

 

79

%

Exploration

 

0.05

 

0.70

 

(0.65

)

(93

)%

Depreciation, depletion and amortization

 

26.03

 

24.04

 

1.99

 

8

%

General and administrative

 

11.81

 

10.82

 

0.99

 

9

%

Operating expenses

 

$

54.38

 

$

50.42

 

$

3.96

 

8

%

 

Lease Operating Expense.  Our lease operating expenses increased $5.1 million, or 40%, to $18.0 million for the three months ended June 30, 2014 from $12.9 million for the three months ended June 30, 2013 and decreased on an equivalent basis from $10.50 per Boe to $8.67 per Boe. The aggregate increase in lease operating expenses was related to increased production volumes attributable to our drilling program. During the quarter ended June 30, 2014, three of the largest components of lease operating expenses were well servicing, compression, and pumping which increased $1.8 million, $1.8 million and $756,000, respectively, over the comparable period in 2013. The decrease in lease operating expenses on an equivalent basis was primarily related to higher production from our horizontal wells in the Wattenberg Field.

 

Severance and ad valorem taxes.  Our severance and ad valorem taxes increased $10.9 million, or 204%, to $16.3 million for the three months ended June 30, 2014 from $5.4 million for the three months ended June 30, 2013. The increase was primarily related to a 69% increase in production volumes during the three months ended June 30, 2014 over the comparable period in 2013.  Colorado has higher severance and ad valorem tax rates than Arkansas and contributed a greater percentage of production for the three months ended June 30, 2014 when compared to the same period in 2013. In addition, our increase in new production during 2013 in the Wattenberg Field resulted in a higher than expected lag in the amount of ad valorem tax credits eligible for deduction against severance taxes generated in the current year because ad valorem taxes are not eligible for deduction the first year a well is completed.

 

Exploration costs.  Our exploration expense decreased $766,000 to $96,000 during the three months ended June 30, 2014 from $862,000 for the three months ended June 30, 2013. During the three months ended June 30, 2013 a seismic acquisition project in the Wattenberg Field was completed which resulted in charges of approximately $700,000. We did not complete any material seismic acquisitions during the three months ended June 30, 2014.

 

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Table of Contents

 

Depreciation, depletion and amortization.  Our depreciation, depletion, and amortization expense increased $24.6 million, or 83%, to $54.1 million for the three months ended June 30, 2014 from $29.5 million for the three months ended June 30, 2013. Our depreciation, depletion and amortization expense per Boe increased $1.99, or 8% to $26.03 for the three months ended June 30, 2014 as compared to $24.04 for the three months ended June 30, 2013. This increase was primarily the result of a significant increase in productive assets with a proved reserve rate increase of 27% period over period and a proved developed reserve rate increase of 12% period over period.

 

General and administrative. Our general and administrative expense increased $11.3 million, or 85%, to $24.6 million for the three months ended June 30, 2014 from $13.3 million for the comparable period ended June 30, 2013 and increased on an equivalent basis to $11.81 per Boe from $10.82 per Boe. During the three months ended June 30, 2014, wages and benefits and stock-based compensation were $6.3 million and $4.7 million higher, respectively, than the same period in 2013. The increases in wages and benefits and a portion of stock-based compensation are due to an increase in headcount as a result of our accelerated drilling program between the three month periods ended June 30, 2014 and 2013. The majority of the increase in general and administrative expense on an equivalent basis was related to executive departures which resulted in charges for cash severance and stock-based compensation of $2.9 million and $3.7 million, respectively.

 

Derivative gain (loss).  Our derivative loss increased $34.9 million to $27.3 million for the three month period ended June 30, 2014 from a $7.6 million gain for the comparable period in 2013. The loss incurred was primarily the result of realized prices being greater than the contract prices. Please refer to Note 10 — Derivatives above for additional discussion.

 

Interest expense.  Our interest expense for the three months ended June 30, 2014 increased $3.5 million, or 59%, to $9.4 million compared to $5.9 million for the three months ended June 30, 2013. The increase for the three months ended June 30, 2014 is primarily due to the issuance of the add-on of $200 million of 6.75% Senior Notes during the fourth quarter of 2013. Interest expense, including amortization of the premium and financing costs, on the 6.75% Senior Notes for the three month periods ended June 30, 2014 and 2013 was $8.5 million and $4.8 million, respectively. Average debt outstanding for the three months ended June 30, 2014 was $500.0 million as compared to $292.5 million for the comparable period in 2013.

 

Income tax expense. Our estimate for federal and state income taxes for the three months ended June 30, 2014 was $800,000 from continuing operations as compared to $9.3 million for the three months ended June 30, 2013. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. Our effective tax rate for the three month periods ended June 30, 2014 and 2013 was 38.5%, which differs from the U.S. statutory income tax rate primarily due to the effects of state income taxes.

 

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

 

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

 

 

 

Six Months Ended June 30,

 

 

 

2014

 

2013

 

Change

 

Percent
Change

 

 

 

(In thousands, except percentages)

 

Revenues:

 

 

 

 

 

 

 

 

 

Crude oil sales

 

$

231,191

 

$

136,849

 

$

94,342

 

69

%

Natural gas sales

 

38,249

 

18,028

 

20,221

 

112

%

Natural gas liquids sales

 

9,630

 

7,882

 

1,748

 

22

%

CO2 sales

 

7

 

66

 

(59

)

(89

)%

Product revenue

 

$

279,077

 

$

162,825

 

$

116,252

 

71

%

 

 

 

 

 

 

 

 

 

 

Sales Volumes:

 

 

 

 

 

 

 

 

 

Crude oil (MBbls)

 

2,540.6

 

1,521.2

 

1,019.4

 

67

%

Natural gas (MMcf)

 

6,786.3

 

3,960.5

 

2,825.8

 

71

%

Natural gas liquids (MBbls)

 

180.8

 

154.1

 

26.7

 

17

%

Crude oil equivalent (MBoe)(1)

 

3,852.4

 

2,335.4

 

1517.0

 

65

%

 

 

 

 

 

 

 

 

 

 

Average Sales Prices (before derivatives)(2)

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

91.00

 

$

89.96

 

$

1.04

 

1

%

Natural gas (per Mcf)

 

$

5.64

 

$

4.55

 

$

1.09

 

24

%

Natural gas liquids (per Bbl)

 

$

53.26

 

$

51.15

 

$

2.11

 

4

%

Crude oil equivalent (per Boe)(1)

 

$

72.44

 

$

69.69

 

$

2.75

 

4

%

 

 

 

 

 

 

 

 

 

 

Average Sales Prices (after derivatives)(2)

 

 

 

 

 

 

 

 

 

Crude oil (per Bbl)

 

$

88.01

 

$

87.83

 

$

0.18

 

0

%

Natural gas (per Mcf)

 

$

5.56

 

$

4.62

 

$

0.94

 

20

%

Natural gas liquids (per Bbl)

 

$

53.26

 

$

51.15

 

$

2.11

 

4

%

Crude oil equivalent (per Boe)(1)

 

$

70.33

 

$

68.41

 

$

1.92

 

3

%

 

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

(2)  The derivatives economically hedge the price we receive for crude oil and natural gas.

 

Revenues increased by 71%, to $279.1 million for the six months ended June 30, 2014 compared to $162.8 million for the six months ended June 30, 2013 due primarily to the increase in oil, natural gas, and natural gas liquids production of 67%, 71%, and 17%, respectively, for the comparable periods. An increase in average sales price on an equivalent basis of 4% for the six months ended June 30, 2014 when compared to the same period in 2013 also contributed to the increase in revenues. Please refer to Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013 above for additional discussion.

 

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

 

 

 

Six Months Ended June 30,

 

 

 

2014

 

2013

 

Change

 

Percent
Change

 

 

 

(In thousands, except percentages)

 

Expenses:

 

 

 

 

 

 

 

 

 

Lease operating

 

$

35,099

 

$

24,029

 

$

11,070

 

46

%

Severance and ad valorem taxes

 

27,013

 

10,165

 

16,848

 

166

%

Exploration

 

1,179

 

1,424

 

(245

)

(17

)%

Depreciation, depletion and amortization

 

95,248

 

52,880

 

42,368

 

80

%

General and administrative

 

48,261

 

26,449

 

21,812

 

82

%

Operating expenses

 

$

206,800

 

$

114,947

 

$

91,853

 

80

%

 

 

 

 

 

 

 

 

 

 

Selected Costs ($ per Boe):

 

 

 

 

 

 

 

 

 

Lease operating

 

$

9.11

 

$

10.29

 

$

(1.18

)

(11

)%

Severance and ad valorem taxes

 

7.01

 

4.35

 

2.66

 

61

%

Exploration

 

0.31

 

0.61