XNYS:KOG Kodiak Oil & Gas Corp. Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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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, 2012

 

Commission File No. 001-32920

 

(Exact name of registrant as specified in its charter)

 

Yukon Territory

 

N/A

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification No.)

 

1625 Broadway, Suite 250

Denver, Colorado 80202

(Address of principal executive offices, including zip code)

 

(303) 592-8075

(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. Yes x No o

 

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x No o

 

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 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 o No x

 

263,689,108 shares, no par value, of the Registrant’s common stock were issued and outstanding as of August 1, 2012.

 

 

 




Table of Contents

 

PART 1—FINANCIAL INFORMATION

 

ITEM 1.  FINANCIAL STATEMENTS

 

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)

 

 

 

June 30, 2012

 

December 31, 2011

 

ASSETS

 

 

 

 

 

Current Assets:

 

 

 

 

 

Cash and cash equivalents

 

$

13,496

 

$

81,604

 

Cash held in escrow

 

 

12,194

 

Accounts receivable

 

 

 

 

 

Trade

 

28,254

 

28,835

 

Accrued sales revenues

 

38,970

 

21,974

 

Commodity price risk management asset

 

33,134

 

 

Inventory, prepaid expenses and other

 

19,535

 

24,294

 

Total Current Assets

 

133,389

 

168,901

 

 

 

 

 

 

 

Oil and gas properties (full cost method), at cost:

 

 

 

 

 

Proved oil and gas properties

 

1,357,020

 

598,065

 

Unproved oil and gas properties

 

520,732

 

263,462

 

Wells in progress

 

63,472

 

78,505

 

Equipment and facilities

 

17,934

 

11,186

 

Less-accumulated depletion, depreciation, amortization, and accretion

 

(195,560

)

(135,586

)

Net oil and gas properties

 

1,763,598

 

815,632

 

 

 

 

 

 

 

Cash held in escrow

 

 

691,764

 

Commodity price risk management asset

 

17,990

 

 

Property and equipment, net of accumulated depreciation of $847 at June 30, 2012 and $618 at December 31, 2011

 

1,750

 

1,276

 

Deferred financing costs, net of accumulated amortization of $16,359 at June 30, 2012 and $15,029 at December 31, 2011

 

25,093

 

21,904

 

 

 

 

 

 

 

Total Assets

 

$

1,941,820

 

$

1,699,477

 

 

 

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

107,968

 

$

78,402

 

Accrued interest payable

 

5,328

 

5,808

 

Commodity price risk management liability

 

 

11,925

 

Total Current Liabilities

 

113,296

 

96,135

 

 

 

 

 

 

 

Noncurrent Liabilities:

 

 

 

 

 

Credit facilities

 

 

100,000

 

Senior notes, net of accumulated amortization of bond premium of $73 at June 30, 2012 and $0 at December 31, 2011

 

805,927

 

650,000

 

Commodity price risk management liability

 

 

10,035

 

Deferred tax liability, net

 

25,920

 

 

Asset retirement obligations

 

6,191

 

3,627

 

Total Noncurrent Liabilities

 

838,038

 

763,662

 

 

 

 

 

 

 

Total Liabilities

 

951,334

 

859,797

 

 

 

 

 

 

 

Stockholders’ Equity:

 

 

 

 

 

Common stock - no par value; unlimited authorized

 

 

 

 

 

Issued and outstanding: 263,614,108 shares as of June 30, 2012 and 257,987,413 shares as of December 31, 2011

 

1,000,060

 

944,070

 

Accumulated deficit

 

(9,574

)

(104,390

)

Total Stockholders’ Equity

 

990,486

 

839,680

 

 

 

 

 

 

 

Total Liabilities and Stockholders’ Equity

 

$

1,941,820

 

$

1,699,477

 

 

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

3



Table of Contents

 

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share data)

(Unaudited)

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

Oil sales

 

$

82,390

 

$

21,417

 

$

159,204

 

$

34,437

 

Gas sales

 

3,378

 

696

 

6,500

 

1,010

 

Total revenues

 

85,768

 

22,113

 

165,704

 

35,447

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Oil and gas production

 

17,200

 

4,433

 

34,500

 

7,007

 

Depletion, depreciation, amortization and accretion

 

34,189

 

4,532

 

60,484

 

8,253

 

General and administrative

 

8,142

 

4,189

 

16,040

 

8,907

 

Total operating expenses

 

59,531

 

13,154

 

111,024

 

24,167

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

26,237

 

8,959

 

54,680

 

11,280

 

 

 

 

 

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

 

 

 

 

Gain (loss) on commodity price risk management activities

 

95,572

 

4,854

 

72,232

 

(4,838

)

Interest income (expense), net

 

(3,541

)

19

 

(8,168

)

52

 

Other income

 

724

 

188

 

1,992

 

291

 

Total other income (expense)

 

92,755

 

5,061

 

66,056

 

(4,495

)

 

 

 

 

 

 

 

 

 

 

Income before income taxes

 

118,992

 

14,020

 

120,736

 

6,785

 

 

 

 

 

 

 

 

 

 

 

Income tax expense

 

25,920

 

 

25,920

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

93,072

 

$

14,020

 

$

94,816

 

$

6,785

 

 

 

 

 

 

 

 

 

 

 

Earnings per common share:

 

 

 

 

 

 

 

 

 

Basic

 

$

0.35

 

$

0.08

 

$

0.36

 

$

0.04

 

Diluted

 

$

0.35

 

$

0.08

 

$

0.35

 

$

0.04

 

 

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding:

 

 

 

 

 

 

 

 

 

Basic

 

263,576,093

 

179,228,934

 

263,118,367

 

178,845,012

 

Diluted

 

267,558,510

 

182,312,179

 

267,419,601

 

181,976,807

 

 

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

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Table of Contents

 

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

 

 

 

Six Months Ended June 30,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Cash flows from operating activities:

 

 

 

 

 

Net income

 

$

94,816

 

$

6,785

 

Reconciliation of net income to net cash provided by operating activities:

 

 

 

 

 

Depletion, depreciation, amortization and accretion

 

60,484

 

8,253

 

Amortization of deferred financing costs and debt premium

 

1,257

 

387

 

Unrealized (gain) loss on commodity price risk management activities, net

 

(73,084

)

3,503

 

Stock-based compensation

 

5,090

 

2,486

 

Deferred income taxes

 

25,920

 

 

Loss on sale of facility

 

262

 

 

Changes in current assets and liabilities:

 

 

 

 

 

Accounts receivable-trade

 

581

 

3,811

 

Accounts receivable-accrued sales revenue

 

(16,996

)

(2,866

)

Prepaid expenses and other

 

1,822

 

6,765

 

Accounts payable and accrued liabilities

 

11,010

 

(5,677

)

Accrued interest payable

 

(24,980

)

58

 

Cash held in escrow

 

3,343

 

 

Net cash provided by operating activities

 

89,525

 

23,505

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

Acquired oil and gas properties and facilities

 

(588,420

)

(71,506

)

Oil and gas properties

 

(308,372

)

(64,330

)

Sale of oil and gas properties

 

 

2,132

 

Equipment, facilities and other

 

(6,774

)

(1,164

)

Prepaid tubular goods

 

(7,576

)

(15,018

)

Proceeds from sale of facility

 

299

 

 

Cash held in escrow

 

30,000

 

 

Net cash used in investing activities

 

(880,843

)

(149,886

)

 

 

 

 

 

 

Cash flows from financing activities:

 

 

 

 

 

Borrowings under credit facilities

 

85,000

 

74,808

 

Repayments under credit facilities

 

(185,000

)

 

Proceeds from the issuance of senior notes

 

156,000

 

 

Proceeds from the issuance of common shares

 

1,245

 

1,107

 

Cash held in escrow

 

670,615

 

 

Debt and share issuance costs

 

(4,650

)

(287

)

Net cash provided by financing activities

 

723,210

 

75,628

 

 

 

 

 

 

 

Decrease in cash and cash equivalents

 

(68,108

)

(50,753

)

 

 

 

 

 

 

Cash and cash equivalents at beginning of the period

 

81,604

 

101,198

 

 

 

 

 

 

 

Cash and cash equivalents at end of the period

 

$

13,496

 

$

50,445

 

 

 

 

 

 

 

Supplemental cash flow information:

 

 

 

 

 

Oil & gas property accrual included in accounts payable and accrued liabilities

 

$

71,097

 

$

19,139

 

Oil & gas property acquired through common stock

 

$

49,798

 

$

14,425

 

Asset retirement obligation

 

$

 

$

849

 

Cash paid for interest

 

$

31,920

 

$

2,248

 

Cash paid for income taxes

 

$

 

$

 

 

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

5



Table of Contents

 

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

Note 1—Organization

 

Description of Operations

 

Kodiak Oil & Gas Corp. and its subsidiary (“Kodiak” or the “Company”) is a public company listed for trading on the New York Stock Exchange under the symbol: “KOG”. The Company’s corporate headquarters are located in Denver, Colorado, USA.  The Company is an independent energy company engaged in the exploration, exploitation, development, acquisition and production of crude oil and natural gas in the Rocky Mountain region of the United States.

 

The Company was incorporated (continued) in the Yukon Territory on September 28, 2001.

 

Note 2—Basis of Presentation and Significant Accounting Policies

 

Basis of Presentation

 

The accompanying unaudited condensed consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc. All significant inter-company balances and transactions have been eliminated in consolidation. The Company’s business is transacted in US dollars and, accordingly, the financial statements are expressed in US dollars. The financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in the United States (“GAAP”) for interim financial information and the instructions to Form 10-Q and Regulation S-X and S-K.  In the opinion of management, all adjustments, consisting of normal recurring accruals that are considered necessary for a fair presentation of the interim financial information, have been included. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for a full year.  Kodiak’s 2011 Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q.  Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in Kodiak’s 2011 Annual Report on Form 10-K.

 

The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in ceiling test of oil and natural gas properties; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity derivative instruments; (8) accrued liabilities; (9) valuation of share-based payments and (10) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company evaluates our estimates on an on-going basis and bases our estimates on historical experience and on various other assumptions the Company believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes that our estimates are reasonable.

 

Impairment of Oil and Gas Properties

 

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, an impairment is recognized.

 

Wells in Progress

 

Wells in progress represent the costs associated with wells that have not reached total depth or been completed as of period end. These costs are related to wells that are classified as both proved and unproved. Costs related to wells that are classified as proved are included in the depletion base.  Costs associated with wells that are classified as unproved are excluded from the depletion base.  The costs for unproved wells are then transferred to proved property when proved reserves are determined. The costs then become subject to depletion.

 

Reclassifications

 

The Company has condensed certain line items within the current period financial statements, and certain prior period balances were reclassified to conform to the current year presentation accordingly.  Such reclassifications had no impact on net income, statements of cash flows, working capital or equity previously reported.

 

Recently Issued Accounting Standards

 

In May 2011, the FASB issued Accounting Standards Update 2011-04 (“ASU 2011-04”), Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. ASU 2011-04 changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U.S. GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is applied prospectively. ASU 2011-04 was made effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. The Company believes that the adoption of this standard did not materially expand the condensed consolidated financial statement footnote disclosures.

 

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Table of Contents

 

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date, are not expected to have a material impact on the financial statements upon adoption.

 

Note 3—Acquisitions

 

January 2012 Acquisition

 

On January 10, 2012, the Company acquired two separate private, unaffiliated oil and gas company’s interests in approximately 50,000 net acres of Williston Basin leaseholds, and related producing properties located primarily in McKenzie and Williams Counties, North Dakota, along with various other related rights, permits, contracts, equipment and other assets, including the assignment and assumption of a drilling rig contract for a combination of cash and stock. The sellers received an aggregate of 5.1 million shares of Kodiak’s common stock valued at approximately $49.8 million and cash consideration of approximately $588.4 million. The effective date for the acquisition was September 1, 2011, with purchase price adjustments calculated as of the closing date on January 10, 2012. The acquisition provided strategic additions adjacent to the Company’s core project area and the acquired producing wells contributed revenue of $8.8 million and $20.3 million to Kodiak for the three and six months ended June 30, 2012, respectively.  Total transaction costs related to the acquisition were approximately $295,000, of which $0 and $85,000 were recorded in the statement of operations within the general and administrative expenses line item for the three and six months ended June 30, 2012, respectively. There were no transaction costs related to the acquisition recorded in the statement of operations within the general and administrative expenses line item for the three and six months ended June 30, 2011. No material costs were incurred for the issuance of the 5.1 million shares of common stock.

 

The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of January 10, 2012.  In July 2012, the Company completed the transaction’s post-closing settlement. The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed and is subject to revision as the Company continues to evaluate the fair value of the acquisition (in thousands):

 

 

 

January 10, 2012

 

Preliminary Purchase Price

 

 

 

Consideration Given

 

 

 

Cash from Senior Notes

 

$

588,420

 

Kodiak Oil & Gas Corp. Common Stock (5,055,612 Shares)

 

49,798

*

 

 

 

 

Total consideration given

 

$

638,218

 

 

 

 

 

Preliminary Allocation of Purchase Price

 

 

 

Proved oil and gas properties

 

$

297,090

 

Unproved oil and gas properties

 

313,053

 

Wells in progress

 

25,745

 

Equipment and facilities

 

7,025

 

Total fair value of oil and gas properties acquired

 

642,913

 

 

 

 

 

Working capital

 

(3,895

)

Asset retirement obligation

 

(800

)

 

 

 

 

Fair value of net assets acquired

 

$

638,218

 

 

 

 

 

Working capital acquired was estimated as follows:

 

 

 

Accounts receivable

 

$

7,200

 

Prepaid completion costs

 

465

 

Crude oil inventory

 

540

 

Accrued liabilities

 

(8,300

)

Suspense payable

 

(3,800

)

 

 

 

 

Total working capital

 

$

(3,895

)

 


*                 The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company’s closing stock price of $9.85 on the measurement date of January 10, 2012.

 

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Table of Contents

 

October 2011 Acquisition

 

On October 28, 2011, the Company acquired a private, unaffiliated oil and gas company’s interests in approximately 13,400 net acres of Williston Basin leaseholds, and related producing properties located primarily in Williams County, North Dakota along with various other related rights, permits, contracts, equipment and other assets. The seller received cash consideration of approximately $248.2 million and the effective date was August 1, 2011, with purchase price adjustments calculated as of the closing date on October 28, 2011. The total purchase included approximately $239.9 million related to the acquisition of the properties and approximately $8.6 million related to the assumption of certain working capital items. The acquisition provided strategic additions adjacent to the Company’s core project area and the acquired producing wells contributed revenue of $7.1 million and $15.6 million to Kodiak for the three and six months ended June 30, 2012, respectively. Total transaction costs related to the acquisition incurred were approximately $200,000.  Transaction costs are recorded in the statement of operations within the general and administrative expenses line item.  No transaction costs for this acquisition were recorded within the three and six months ended June 30, 2012 and 2011.

 

The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of October 28, 2011. In February 2012, the Company completed the transaction’s post-closing settlement. The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed and is subject to revision as the Company continues to evaluate the fair value of the acquisition (in thousands):

 

 

 

October 28, 2011

 

Preliminary Purchase Price

 

 

 

Consideration Given

 

 

 

Cash

 

$

248,213

 

 

 

 

 

Total consideration given

 

$

248,213

 

 

 

 

 

Preliminary Allocation of Purchase Price

 

 

 

Proved oil and gas properties

 

$

124,018

 

Unproved oil and gas properties

 

90,161

 

Wells in progress

 

25,720

 

Total fair value of oil and gas properties acquired

 

239,899

 

 

 

 

 

Working capital

 

8,552

 

Asset retirement obligation

 

(238

)

 

 

 

 

Fair value of net assets acquired

 

$

248,213

 

 

 

 

 

Working capital acquired was estimated as follows:

 

 

 

Accounts receivable

 

$

10,260

 

Prepaid drilling costs

 

755

 

Crude oil inventory

 

190

 

Well equipment inventory

 

1,324

 

Accrued liabilities

 

(1,247

)

Suspense payable

 

(2,730

)

 

 

 

 

Total working capital

 

$

8,552

 

 

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Table of Contents

 

June 2011 Acquisition

 

On June 30, 2011,the Company acquired a private, unaffiliated oil and gas company’s interests in approximately 25,000 net acres of Williston Basin leaseholds and related producing properties located in McKenzie County, North Dakota along with various other related rights, permits, contracts, equipment and other assets for a combination of cash and stock. The seller received 2.5 million shares of Kodiak’s common stock valued at approximately $14.4 million and cash consideration of approximately $71.5 million. The effective date for the acquisition was April 1, 2011, with purchase price adjustments calculated as of the closing date on June 30, 2011. The acquisition provided strategic additions to the Company’s core positions in Koala, Smokey and Grizzly Project areas and the acquired producing wells contributed revenue of $400,000 and $836,000 to Kodiak for the three and six months ended June 30, 2012, respectively.  Total transaction costs related to the acquisition were approximately $265,000.  There were no transaction costs related to the acquisition recorded in the statement of operations, within the general and administrative expenses line item, for the three and six months ended June 30, 2012. Transaction costs of $245,000 were recorded within the general and administrative expenses line item for the three and six months ended June 30, 2011, respectively. Costs of $85,000 for issuing and registering with the SEC for the resale of 2.5 million shares of common stock were charged to common stock.

 

The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of June 30, 2011. The transaction’s final settlement was completed in September 2011 resulting in no material changes.  Of the $85.9 million purchase price, $8.0 million was allocated to proved oil and gas properties, $77.8 million was allocated to unproved oil and gas properties and the remaining $100,000 was working capital and asset retirement obligation adjustments.

 

Pro Forma Financial Information

 

The following unaudited pro forma financial information represents the combined results for the Company and the properties acquired in January 2012, October 2011 and June 2011 for the three and six months ended June 30, 2012 and 2011 as if the acquisitions had occurred on January 1, 2011 (in thousands, except per share data). For purposes of the pro forma it was assumed that the $650.0 million 8.125% Senior Notes were issued on January 1, 2011 and that the stand-by bridge was not utilized. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $0 and $600,000 for the three and six months ended June 30, 2012, respectively, as compared to $6.5 million and $10.9 million for the three and six months ended June 30, 2011, respectively. The pro forma information includes the effects of adjustments for amortization of financing costs of $400,000 and $800,000 for the three and six months ended June 30, 2011, respectively.  For the three and six months ended June 30, 2012, there was no pro forma adjustments for the amortization of deferred financing costs.  For the three and six months ended June 30, 2012, there was a pro forma adjustment reducing interest expense of $0 and $400,000, respectively. For the three and six months ended June 30, 2011, there was no pro forma adjustment for interest expense. The pro forma financial information includes total capitalization of interest expense of $12.9 million and $24.9 million for the three and six months ended June 30, 2012, respectively, as compared to $14.3 million and $28.6 million for the three and six months ended June 30, 2011, respectively.  The pro forma results do not include any cost savings or other synergies that may result from the acquisitions or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisitions had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Operating revenues

 

$

85,768

 

$

38,970

 

$

167,504

 

$

61,717

 

Net income

 

$

93,072

 

$

20,864

 

$

96,040

 

$

16,195

 

Earnings per common share

 

 

 

 

 

 

 

 

 

Basic

 

$

0.35

 

$

0.11

 

$

0.36

 

$

0.09

 

Diluted

 

$

0.35

 

$

0.11

 

$

0.36

 

$

0.09

 

 

9



Table of Contents

 

Note 4—Long-Term Debt

 

As of the dates indicated, the Company’s long-term debt consisted of the following (in thousands):

 

 

 

June 30, 2012

 

December 31, 2011

 

 

 

 

 

 

 

Credit Facility due October 2016

 

$

 

$

 

Second Lien Credit Agreement due April 2017

 

 

100,000

 

8.125% Senior Notes due December 2019

 

800,000

 

650,000

 

Unamortized Premium on 8.125% Senior Notes

 

5,927

 

 

Total Long-Term Debt

 

$

805,927

 

$

750,000

 

Less: Current Portion of Long Term Debt

 

 

 

Total Long-Term Debt, Net of Current Portion

 

$

805,927

 

$

750,000

 

 

Credit Facility

 

Kodiak Oil & Gas (USA) Inc. (the “Borrower”), a wholly-owned subsidiary of Kodiak Oil & Gas Corp., has in place a credit agreement (“credit facility”) with a syndicate of banks.  The maximum credit available under the credit facility is $750.0 million with a borrowing base of $225.0 million at June 30, 2012. Redetermination of the borrowing base occurs semi-annually, on April 1 and October 1. Additionally, the Company may elect a redetermination of the borrowing base one time during any six month period.  In July 2012, the Company elected an unscheduled interim redetermination of its borrowing base.  As a result, the borrowing base was increased to $375.0 million effective August 2, 2012. The credit facility matures on October 28, 2016.

 

Interest on the credit facility is payable at one of the following two variable rates: the alternate base rate for ABR loans or the adjusted LIBO rate for Eurodollar loans, as selected by the Company, plus an additional percentage that can vary on a daily basis and is based on the daily unused portion of the facility. This additional percentage is referred to as the “Applicable Margin” and varies depending on the type of loan. The Applicable Margin for the ABR loans is a sliding scale of 0.75% to 1.75%, depending on borrowing base usage. The Applicable Margin on the adjusted LIBO rate is a sliding scale of 1.75% to 2.75%, depending on borrowing base usage. Additionally, the credit facility provides for a borrowing base fee of 0.5% and a commitment fee of 0.375% to 0.50%, depending on borrowing base usage. The grid below shows the Applicable Margin options depending on the applicable Borrowing Base Utilization Percentage (as defined in the Credit Agreement) as of June 30, 2012 and the date of this filing:

 

Borrowing Base Utilization Grid

 

Borrowing Base Utilization Percentage

 

<25.0%

 

>25.0% <50.0%

 

>50.0% <75.0%

 

>75.0% <90.0%

 

>90.0%

 

Eurodollar Loans

 

1.75

%

2.00

%

2.25

%

2.50

%

2.75

%

ABR Loans

 

0.75

%

1.00

%

1.25

%

1.50

%

1.75

%

Commitment Fee Rate

 

0.375

%

0.375

%

0.50

%

0.50

%

0.50

%

 

The credit facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on dividends, distributions, redemptions and restricted payments covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on the sale of property, mergers, consolidations and other similar transactions covenants.  Additionally, the credit facility requires the Borrower to enter hedging agreements necessary to support the borrowing base.

 

The credit facility also contains financial covenants requiring the Borrower to comply with a current ratio of consolidated current assets (including unused borrowing capacity) to consolidated current liabilities of not less than 1.0:1.0 and to maintain, on the last day of each quarter, a ratio of total debt to EBITDAX of not greater than (i) 4.75 to 1.0 at the end of each of the two fiscal quarters ending December 31, 2011 and March 31, 2012, (ii) 4.50 to 1.0 at the end of the fiscal quarter ending June 30, 2012, (iii) 4.25 to 1.0 at the end of the fiscal quarter ending September 30, 2012, and (iv) 4.0 to 1.0 at the end of each fiscal quarter thereafter.  As of June 30, 2012, the Company was in compliance with all financial covenants under the credit facility.

 

As of June 30, 2012, the Company had no outstanding borrowings under the credit facility and as such, the available credit under the credit facility at that date was $225.0 million. Subsequent to June 30, 2012, the Company borrowed $20 million which is currently outstanding. Any borrowings under the credit facility are collateralized by the Borrower’s oil and gas producing properties, the Borrower’s personal property and the equity interests of the Borrower held by the Company. The Company has entered into crude oil hedging transactions with Wells Fargo. The Company’s obligations under the hedging contracts with Wells Fargo are secured by the credit facility.

 

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Table of Contents

 

Second Lien Credit Agreement

 

On January 10, 2012, the Company terminated the second lien credit agreement and repaid the $100.0 million of outstanding debt, and incurred a $3.0 million prepayment penalty in connection therewith. The Company recorded the $3.0 million prepayment penalty in the first quarter of 2012 within the interest income (expense), net line item of the statement of operations.

 

Senior Notes

 

In November 2011, the Company issued at par $650.0 million of 8.125% Senior Notes due December 1, 2019 (the “Senior Notes”). On May 17, 2012, the Company issued an additional $150.0 million aggregate principal amount of our existing 8.125% Senior Notes at a price of 104.0% of par, resulting in net proceeds of $151.8 million, after deducting discounts and fees. The net proceeds from the May 2012 offering were used to repay all borrowings on the credit facility and to fund the Company’s ongoing capital expenditure program and general corporate purposes. The interest on the Senior Notes is payable on June and December 1 of each year, beginning June 1, 2012. The Senior Notes were issued under an Indenture, dated as of November 23, 2011 (the “Indenture”) among the Company, Kodiak Oil & Gas (USA) Inc. (the “Guarantor”), U.S. Bank National Association, as the trustee (the “Trustee”) and Computershare Trust Company of Canada, as the Canadian trustee. The Indenture contains affirmative and negative covenants that, among other things, limit the Company’s and the Guarantor’s ability to make investments; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company’s affiliates; pay dividends or make other distributions on capital stock or prepay subordinated indebtedness; and create unrestricted subsidiaries. The Indenture also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the Senior Notes shall become due and payable immediately without any declaration or other act of the Trustee or the holders of the Senior Notes. Upon the occurrence of certain other events of default, the Trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under its Senior Notes as of June 30, 2012, and through the filing of this report.

 

The Senior Notes are redeemable by the Company at any time on or after December 1, 2015, at the redemption prices set forth in the Indenture. The Senior Notes are redeemable by the Company prior to December 1, 2015, at the redemption prices plus a “make-whole” premium set forth in the Indenture. The Company is also entitled to redeem up to 35% of the aggregate principal amount of the Senior Notes before December 1, 2014 with net proceeds that the Company raises in equity offerings at a redemption price equal to 108.125% of the principal amount of the Senior Notes being redeemed, plus accrued and unpaid interest. If the Company undergoes a change of control on or prior to January 1, 2013, it may redeem all, but not less than all, of the Senior Notes at a redemption price equal to 110% of the principal amount of the Senior Notes redeemed plus accrued and unpaid interest. The Company estimates that the fair value of this option is immaterial at June 30, 2012.

 

The Senior Notes are jointly and severally guaranteed on a senior basis by the Guarantor and by certain of the Company’s future subsidiaries. The Senior Notes and the guarantees thereof will be the Company and the Guarantor’s general senior obligations and will, prior to the release of the amounts held in escrow, be secured by the net proceeds of the Company’s offer and sale of the Senior Notes and certain other funds held in the escrow account pursuant to an escrow agreement (upon release of such escrow property, the Senior Notes will not be secured), rank senior in right of payment to any of the Company’s and the Guarantor’s future subordinated indebtedness, rank equal in right of payment with any of the Company’s and the Guarantor’s existing and future senior indebtedness, rank effectively junior in right of payment to the Company’s and the Guarantor’s existing and future secured indebtedness (including indebtedness under the Company’s credit facility), to the extent of the value of the Company’s and the Guarantor’s assets constituting collateral securing such indebtedness, and rank effectively junior in right of payment to any indebtedness or liabilities of any the Company’s future subsidiaries of any subsidiary that does not guarantee the Senior Notes.

 

In connection with the sale of the Senior Notes, the Company entered into a registration rights agreement that provides the holders of the Senior Notes certain rights relating to the registration of the Senior Notes under the Securities Act. Pursuant to the registration rights agreement, the Company agreed to conduct a registered exchange offer for the Senior Notes or cause to become effective a shelf registration statement providing for the resale of the Senior Notes, each in accordance with the terms of the agreement. If the Company fails to comply with certain obligations under the agreement, it will be required to pay liquidated damages by way of additional interest on the Senior Notes. On July 20, 2012, the Company filed a registration statement on Form S-4 (No. 333-182783) with the SEC in accordance with such registration rights agreement, although the registration statement is not yet effective.

 

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Table of Contents

 

Deferred Financing Costs

 

As of June 30, 2012, the Company had deferred financing costs of $25.1 million related to its credit facility and Senior Notes. Deferred financing costs include origination, legal, engineering, and other fees incurred in connection with the Company’s credit facilities and Senior Notes. The Company recorded amortization expense for the three and six months ended June 30, 2012 of $690,000 and $1.3 million, respectively, as compared to $200,000 and $387,000 for the three and six months ended June 30, 2011, respectively.

 

Interest Incurred On Long-Term Debt

 

Total interest expense incurred during the three and six months ended June 30, 2012 was approximately $15.0 million and $28.5 million, respectively, as compared to $1.1 million and $2.2 million for the three and six months ended June 30, 2011, respectively.  The Company capitalized interest costs of $12.0 million and $24.5 million for the three and six months ended June 30, 2012, respectively, as compared to $1.1 million and $2.2 million for the three and six months ended June 30, 2011, respectively.

 

Note 5— Income Taxes

 

The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to its year-to-date income or loss.  As of March 31, 2012, the Company had not generated taxable income to-date and had incurred a cumulative book loss over the previous three fiscal years, which led the Company to provide a valuation allowance against both U.S. and Canadian net deferred tax assets, since it could not conclude that it is more likely than not that the net deferred tax assets would be fully realized.

 

During the second quarter of 2012, the Company concluded that it is more likely than not that it would be able to realize the benefits of its U.S. deferred tax assets, and that it was appropriate to release the U.S. valuation allowance against it.  This decision was based on the fact that for the three-year period ended June 30, 2012, the Company has reported positive cumulative net income.  Additionally, for the three months ended June 30, 2012, the Company recognized income before taxes of $119.0 million.  As a result of the second quarter 2012 income before income taxes, the Company is in a net deferred tax liability position as of June 30, 2012.

 

The Company continues to provide a full valuation allowance on the Canadian net deferred tax assets as ultimate realization of these deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment.  As the Company does not have revenue generating assets in Canada, the Company does not expect to utilize the Canadian net deferred tax assets.  The Company will continue to evaluate whether a valuation allowance on a separate country basis is needed in future reporting periods.

 

The effective tax rate for the six months ended June 30, 2012, was 22.33%, which differs from the statutory federal income tax rate as shown in the below table.  Our actual effective tax rate for 2012 could vary significantly from this rate based on our actual results.  For the three and six months ended June 30, 2011, no income tax expense was recognized.

 

 

 

Six Months Ended

 

 

 

June 30, 2012

 

 

 

 

 

Federal

 

35.00

%

State

 

2.14

%

Other

 

0.77

%

Change in Valuation Allowance (U.S.)

 

-15.82

%

Change in Valuation Allowance (Canada)

 

0.24

%

 

 

 

 

Net

 

22.33

%

 

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of June 30, 2012, the Company had no provision for interest or penalties related to uncertain tax positions. The Company files income tax returns in Canada and U.S. federal jurisdiction and various states. There are currently no Canadian or U.S. federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service, state or local tax authorities for tax years ended on or before December 31, 2007 or Canadian tax examinations by the Canadian Revenue Agency for tax years ended on or before December 31, 2001. Although certain tax years are closed under the statute of limitations, tax authorities can still adjust tax losses being carried forward to open tax years.

 

12



Table of Contents

 

Note 6— Commodity Derivative Instruments

 

Through its wholly-owned subsidiary Kodiak Oil & Gas (USA) Inc., the Company has entered into commodity derivative instruments, as described below. The Company has utilized swaps or “no premium” collars to reduce the effect of price changes on a portion of our future oil production. A swap requires us to pay the counterparty if the settlement price exceeds the strike price and the same counterparty is required to pay us if the settlement price is less than the strike price.  A collar requires us to pay the counterparty if the settlement price is above the ceiling price and requires the counterparty to pay us if the settlement price is below the floor price. The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

 

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with three counterparties. The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

 

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity price risk management assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity price risk management activities line on the consolidated statement of income. The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments.

 

13



Table of Contents

 

The Company’s commodity derivative contracts as of June 30, 2012 are summarized below:

 

Contract Type

 

Counterparty

 

Basis(1)

 

Quantity (Bbl/d)

 

Strike Price
($/Bbl)

 

Term

Collar

 

Wells Fargo Bank, N.A.

 

NYMEX

 

400

 

$70.00 - $95.56

 

Jul 1, 2012—Dec 31, 2012

Collar

 

Wells Fargo Bank, N.A.

 

NYMEX

 

230

 

$85.00 - $117.73

 

Jul 1, 2012—Dec 31, 2012

Collar

 

Shell Trading (U.S.)

 

NYMEX

 

500

 

$85.00 - $117.00

 

Jul 1, 2012—Dec 31, 2013

Collar

 

Wells Fargo Bank, N.A.

 

NYMEX

 

300 - 425

 

$85.00 - $102.75

 

Jan 1, 2013—Dec 31, 2015

 

 

 

 

 

 

 

 

 

 

 

Contract Type

 

Counterparty

 

Basis(1)

 

Quantity (Bbl/d)

 

Swap Price
($/Bbl)

 

Term

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

100

 

$

84.00

 

Jul 1, 2012—Dec 31, 2012

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

136

 

$

88.30

 

Jul 1, 2012—Dec 31, 2012

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

24

 

$

90.28

 

Jul 1, 2012—Dec 31, 2012

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

500

 

$

85.00

 

Jul 1, 2012—Dec 31, 2012

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

1,000

 

$

85.07

 

Jul 1, 2012—Dec 31, 2012

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

1,000

 

$

102.05

 

Jul 1, 2012—Dec 31, 2012

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

1,000

 

$

102.88

 

Jul 1, 2012—Dec 31, 2012

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

500

 

$

107.20

 

Jul 1, 2012—Dec 31, 2012

Swap

 

Shell Trading (U.S.)

 

NYMEX

 

250

 

$

85.01

 

Jul 1, 2012—Dec 31, 2012

Swap

 

Shell Trading (U.S.)

 

NYMEX

 

2,000

 

$

96.88

 

Jul 1, 2012—Dec 31, 2012

Swap

 

Shell Trading (U.S.)

 

NYMEX

 

500

 

$

102.85

 

Jul 1, 2012—Dec 31, 2012

Swap

 

Credit Suisse International

 

NYMEX

 

500

 

$

106.85

 

Jul 1, 2012—Dec 31, 2012

Swap

 

Credit Suisse International

 

NYMEX

 

500

 

$

107.25

 

Jul 1, 2012—Dec 31, 2012

Swap

 

Credit Suisse International

 

NYMEX

 

1,000

 

$

102.83

 

Jul 1, 2012—Dec 31, 2012

2012 Total/Average

 

 

 

9,010

 

$

98.22

 

 

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

79

 

$

84.00

 

Jan 1, 2013—Dec 31, 2013

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

427

 

$

88.30

 

Jan 1, 2013—Dec 31, 2013

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

24

 

$

90.28

 

Jan 1, 2013—Dec 31, 2013

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

500

 

$

85.00

 

Jan 1, 2013—Dec 31, 2013

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

400

 

$

85.07

 

Jan 1, 2013—Dec 31, 2013

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

425

 

$

93.20

 

Jan 1, 2013—Dec 31, 2013

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

1,000

 

$

104.13

 

Jan 1, 2013—Dec 31, 2013

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

1,000

 

$

101.55

 

Jan 1, 2013—Dec 31, 2013

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

1,000

 

$

95.95

 

Jan 1, 2013—Dec 31, 2013

Swap

 

Shell Trading (U.S.)

 

NYMEX

 

250

 

$

85.01

 

Jan 1, 2013—Dec 31, 2013

Swap

 

Shell Trading (U.S.)

 

NYMEX

 

500

 

$

101.32

 

Jan 1, 2013—Dec 31, 2013

Swap

 

Shell Trading (U.S.)

 

NYMEX

 

500

 

$

95.98

 

Jan 1, 2013—Dec 31, 2013

Swap

 

Credit Suisse International

 

NYMEX

 

1,000

 

$

101.60

 

Jan 1, 2013—Dec 31, 2013

Swap

 

Credit Suisse International

 

NYMEX

 

1,000

 

$

95.98

 

Jan 1, 2013—Dec 31, 2013

2013 Total/Average

 

 

 

8,105

 

$

96.45

 

 

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

69

 

$

84.00

 

Jan 1, 2014—Dec 31, 2014

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

360

 

$

88.30

 

Jan 1, 2014—Dec 31, 2014

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

21

 

$

90.28

 

Jan 1, 2014—Dec 31, 2014

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

350

 

$

93.20

 

Jan 1, 2014—Dec 31, 2014

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

1,000

 

$

85.07

 

Jan 1, 2014—Dec 31, 2014

Swap

 

Credit Suisse International

 

NYMEX

 

1,000

 

$

100.05

 

Jan 1, 2014—Dec 31, 2014

2014 Total/Average

 

 

 

2,800

 

$

91.86

 

 

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

59

 

$

84.00

 

Jan 1, 2015—Oct 31, 2015

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

317

 

$

88.30

 

Jan 1, 2015—Sep 30, 2015

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

46

 

$

90.28

 

Jan 1, 2015—Oct 31, 2015

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

300

 

$

93.20

 

Jan 1, 2015—Dec 31, 2015

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

1,000

 

$

85.07

 

Jan 1, 2015—Dec 31, 2015

2015 Total/Average

 

 

 

1,625

 

$

87.13

 

 

 


(1) NYMEX refers to quoted prices on the New York Mercantile Exchange

 

14



Table of Contents

 

The following table details the fair value of the derivatives recorded in the applicable consolidated balance sheet, by category (in thousands):

 

Underlying Commodity

 

Location on
Balance Sheet

 

As of June 30, 2012

 

As of December 31, 2011

 

Crude oil derivative contract

 

Current assets

 

$

33,134

 

$

 

Crude oil derivative contract

 

Noncurrent assets

 

$

17,990

 

$

 

Crude oil derivative contract

 

Current liabilities

 

$

 

$

11,925

 

Crude oil derivative contract

 

Noncurrent liabilities

 

$

 

$

10,035

 

 

The amount of gain (loss) recognized in the statements of operations related to our derivative financial instruments was as follows (in thousands):

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Unrealized gain (loss) on oil contracts

 

$

91,700

 

$

5,847

 

$

73,084

 

$

(3,503

)

Realized gain (loss) on oil contracts

 

3,872

 

(993

)

(852

)

(1,335

)

Gain (loss) on commodity price risk management activities

 

$

95,572

 

$

4,854

 

$

72,232

 

$

(4,838

)

 

Unrealized gains and losses resulting from derivatives are recorded at fair value on the consolidated balance sheet and changes in fair value are recognized on the consolidated statement of operations. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity price risk management activities line on the consolidated statement of income.

 

Note 7—Asset Retirement Obligations

 

The Company follows accounting for asset retirement obligations in accordance with ASC 410, Asset Retirement and Environmental Obligations, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in wells at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement costsare depleted as a component of the full cost pool using the unit of production method.

 

 

 

For the Six Months
Ended June 30, 2012

 

For the Year Ended
December 31, 2011

 

 

 

($ in thousands)

 

 

 

 

 

 

 

Balance beginning of period

 

$

3,627

 

$

1,968

 

Liabilities incurred or acquired

 

2,386

 

1,655

 

Liabilities settled

 

(42

)

(610

)

Revisions in estimated cash flows

 

 

418

 

Accretion expense

 

220

 

196

 

Balance end of period

 

$

6,191

 

$

3,627

 

 

Note 8—Fair Value Measurements

 

ASC Topic 820, Fair Value Measurement and Disclosure, 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:

 

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Table of Contents

 

·                  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;

 

·                  Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.

 

The financial assets and liabilities are 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.  There were no significant assets or liabilities that were measured at fair value on a non-recurring basis in periods after initial recognition.

 

The Company’s non-recurring fair value measurements include asset retirement obligations, please refer to Note 7—Asset Retirement Obligations, and the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to Note 3—Acquisitions.

 

The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.

 

The fair value of assets and liabilities acquired through business combinations is calculated using a discounted-cash flow approach using level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices and operating costs.

 

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 (in thousands):

 

 

 

Fair Value Measurements at June 30, 2012 Using

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

 

 

 

 

 

 

 

 

 

 

Financial Assets:

 

 

 

 

 

 

 

 

 

Commodity price risk management asset

 

$

 

$

51,124

 

$

 

$

51,124

 

 

The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above:

 

Commodity Derivative Instruments

 

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. At June 30, 2012 and December 31, 2011, derivative instruments utilized by the Company consist of both “no premium” collars and swaps. The crude oil derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

 

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Table of Contents

 

Fair Value of Financial Instruments

 

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s credit facility approximated fair value as it bears interest at variable rates over the term of the loan. The fair value of the second lien credit agreement at December 31, 2011 was based on the amount paid on January 10, 2012 to extinguish the debt. The fair value of the Senior Notes was derived from available market data (Level 2 inputs). This disclosure (in thousands) does not impact our financial position, results of operations or cash flows.

 

 

 

At June 30, 2012

 

At December 31, 2011

 

 

 

Carrying
Amount

 

Fair Value

 

Carrying
Amount

 

Fair Value

 

 

 

 

 

 

 

 

 

 

 

Credit Facility

 

$

 

$

 

$

 

$

 

Second Lien Credit Agreement

 

$

 

$

 

$

100,000

 

$

103,000

 

8.125% Senior Notes

 

$

805,927

 

$

824,000

 

$

650,000

 

$

656,500

 

 

Note 9—Share-Based Payments

 

The Company has granted options to directors, officers, and employees of the Company under the 2007 Stock Incentive Plan, amended on June 3, 2010 and further amended on June 15, 2011 (the “Plan”). The Plan authorizes the Company to issue stock options, stock appreciation rights, restricted stock and restricted stock units, performance awards, other stock grants and other stock-based awards to any employee, consultant, independent contractor, director or officer providing services to the Company or to an affiliate of the Company. The maximum number of shares of common stock available for issuance under the Plan is equal to 14% of the Company’s issued and outstanding shares of common stock, as calculated on January 1 of each respective year, subject to adjustment as provided in the Plan.  As of January 1, 2012, the maximum number of shares issuable under the Plan, including those previously issued thereunder, was approximately 36.1 million shares.

 

Stock Options

 

Total compensation expense related to the stock options of $1.6 million and $3.0 million was recognized during the three and six months ended June 30, 2012, respectively, as compared to $652,000 and $2.0 million for the three and six months ended June 30, 2011, respectively. As of June 30, 2012, there was $9.7 million of total unrecognized compensation cost related to stock options, which is expected to be amortized over a weighted-average period of 2.0 years.

 

Compensation expense related to stock options is calculated using the Black-Scholes-Merton valuation model. Expected volatilities are based on the historical volatility of Kodiak’s common stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in the Company’s common stock price and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms. The following assumptions were used for the Black-Scholes-Merton model to calculate the share-based compensation expense for the periods presented:

 

 

 

For the Six Months
Ended June 30, 2012

 

For the Year Ended
December 31, 2011

 

 

 

 

 

 

 

Risk free rates

 

0.77 - 1.48%

 

1.06 - 2.57%

 

Dividend yield

 

0%

 

0%

 

Expected volatility

 

87.82 - 90.25%

 

90.43 - 94.97%

 

Weighted average expected stock option life

 

5.82 years

 

6.01 years

 

 

 

 

 

 

 

The weighted average fair value at the date of grant for stock options granted is as follows:

 

 

 

 

 

 

 

 

 

 

 

Weighted average fair value per share

 

$

6.59

 

$

5.10

 

Total options granted

 

972,500

 

1,712,500

 

 

 

 

 

 

 

Total weighted average fair value of options granted

 

$

6,408,775

 

$

8,733,750

 

 

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Table of Contents

 

A summary of the stock options outstanding as of January 1, 2012 and June 30, 2012 is as follows:

 

 

 

 

 

Weighted

 

 

 

 

 

Average

 

 

 

Number of

 

Exercise

 

 

 

Options

 

Price

 

Balance outstanding at January 1, 2012

 

6,591,158

 

$

3.77

 

 

 

 

 

 

 

Granted

 

972,500

 

9.08

 

Canceled

 

(208,035

)

5.66

 

Exercised

 

(541,083

)

2.31

 

 

 

 

 

 

 

Balance outstanding at June 30, 2012

 

6,814,540

 

$

4.59

 

 

 

 

 

 

 

Options exercisable at June 30, 2012

 

4,109,540

 

$

3.03

 

 

At June 30, 2012, stock options outstanding were as follows:

 

 

 

Options Outstanding

 

Options Exercisable

 

Range of
Exercise
Prices

 

Number of
Options
Outstanding

 

Weighted
Average
Remaining
Contractual
Life (Years)

 

Weighted
Average
Exercise Price

 

Number of
Options
Exercisable

 

Weighted
Average
Remaining
Contractual
Life (Years)

 

Weighted
Average
Exercise Price

 

$ 0.36-$1.00

 

259,000

 

6.5

 

$

0.36

 

259,000

 

6.5

 

$

0.36

 

$1.01-$2.00

 

895,917

 

1.9

 

$

1.18

 

895,917

 

1.9

 

$

1.18

 

$2.01-$3.00

 

903,870

 

7.2

 

$

2.36

 

602,870

 

7.0

 

$

2.33

 

$3.01-$4.00

 

1,798,753

 

4.1

 

$

3.47

 

1,709,253

 

4.0

 

$

3.47

 

$4.01-$5.00

 

155,000

 

8.8

 

$

4.47

 

25,000

 

8.4

 

$

4.26

 

$5.01-$6.00

 

293,000

 

8.9

 

$

5.50

 

74,000

 

8.8

 

$

5.38

 

$6.01-$7.00

 

1,127,500

 

7.6

 

$

6.41

 

527,500

 

6.4

 

$

6.37

 

$7.01-$8.00

 

340,000

 

9.6

 

$

7.47

 

16,000

 

8.7

 

$

7.20

 

$8.01-$9.00

 

462,000

 

9.6

 

$

8.72

 

 

0.0

 

$

 

$9.01-$10.53

 

579,500

 

9.5

 

$

9.78

 

 

0.0

 

$

 

 

 

6,814,540

 

6.3

 

$

4.59

 

4,109,540

 

4.6

 

$

3.03

 

 

The aggregate intrinsic value of both outstanding and vested options as of June 30, 2012 was $25.8 million based on the Company’s June 29, 2012 closing common stock price of $8.21 per share. The total grant date fair value of the shares vested during the first half of 2012 was $2.3 million.

 

Restricted Stock Units and Restricted Stock

 

Total compensation expense related to restricted stock units (“RSUs”) and restricted stock of $1.1 million and $2.1 million was recognized during the three and six months ended June 30, 2012, respectively, as compared to $295,000 and $532,000 for the three and six months ended June 30, 2011, respectively. As of June 30, 2012, there was $5.5 million of total unrecognized compensation cost related to the RSUs and restricted stock, which is expected to be amortized over a weighted-average period of 2.1 years.

 

In the fourth quarter 2011, the Company awarded 775,611 performance based RSUs to officers pursuant to the Plan. Subject to the satisfaction of certain 2012 performance-based conditions, the RSUs vest one-quarter per year over a four year service period and the Company began recognizing compensation expense related to these grants beginning in the fourth quarter 2011 over the vesting period. The Company recognizes compensation cost for performance based grants on a tranche level basis over the requisite service period for the entire award. The fair value of RSU’s granted is based on the stock price on the grant date and the Company assumed no annual forfeiture rate.

 

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Table of Contents

 

During 2012, the Company awarded 30,000 shares of restricted stock to its Board of Directors pursuant to the Plan.  These restricted stock shares vest over a four year period and the Company began recognizing compensation expense related to these grants in the first six months of 2012. The Company recognizes compensation cost for these grants on a straight-line basis over the requisite service period for the entire award. The fair value of restricted stock is based on the stock price on the grant date and the Company assumes a 3% annual forfeiture rate.

 

As of June 30, 2012, there were 985,611 unvested RSUs and 30,000 unvested restricted stock shares with a combined weighted average grant date fair value of $8.55 per share. The total fair value vested during the first half of 2012 was $166,000. A summary of the RSUs and restricted stock shares outstanding is as follows:

 

 

 

 

 

Weighted

 

 

 

 

 

Average

 

 

 

Number of

 

Grant Date

 

 

 

Shares

 

Fair Value

 

Non-vested restricted stock and RSUs at January 1, 2012

 

1,008,111

 

$

8.48

 

 

 

 

 

 

 

Granted

 

30,000

 

9.87

 

Forfeited

 

 

 

Vested

 

(22,500

)

7.39

 

Non-vested restricted stock and RSUs at June 30, 2012

 

1,015,611

 

$

8.55

 

 

Note 10—Earnings Per Share

 

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. Diluted net income per common share includes shares of restricted stock units, and the potential dilution that could occur upon exercise of options to acquire common stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of the options (which were assumed to have been made at the average market price of the common shares during the reporting period).

 

In accordance with ASC 260-10-45, Share-Based Payment Arrangements and Participating Securities and the Two-Class Method, the Company’s unvested restricted stock shares are deemed participating securities, since these shares would be entitled to participate in dividends declared on common shares. During periods of net income, the calculation of earnings per share for common stock exclude income attributable to the restricted stock shares from the numerator and exclude the dilutive impact of those shares from the denominator. During periods of net loss, no effect is given to the participating securities because they do not share in the losses of the Company.

 

The performance based restricted stock units and unexercised stock options are not participating securities, since these shares are not entitled to participate in dividends declared on common shares. The number of potentially dilutive shares attributable to the performance based restricted stock units is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the performance measurement period. Please refer to Note 9—Share-Based Payments under the heading Restricted Stock Units and Restricted Stock for additional discussion.

 

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The table below sets forth the computations of basic and diluted net income per share for the three and six months ended June 30, 2012 and 2011 (in thousands, except per share data):

 

 

 

For the Three Months Ended June 30,

 

For the Six Months Ended June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Basic net income

 

$

93,072

 

$

14,020

 

$

94,816

 

$

6,785

 

Income allocable to participating securities

 

(11

)

(2

)

(11

)

(1

)

Diluted net income

 

$

93,061

 

$

14,018

 

$

94,805

 

$

6,784

 

 

 

 

 

 

 

 

 

 

 

Basic weighted average common shares outstanding

 

263,576,093

 

179,228,934

 

263,118,367

 

178,845,012

 

Effect of dilutive securities

 

 

 

 

 

 

 

 

 

Options to purchase common shares

 

5,855,040

 

5,216,158

 

6,244,040

 

5,216,158

 

Assumed treasury shares purchased

 

(2,189,160

)

(2,412,913

)

(2,244,942

)

(2,364,363

)

Unvested restricted stock units

 

316,537

 

280,000

 

302,136

 

280,000

 

Diluted weighted average common shares outstanding

 

267,558,510

 

182,312,179

 

267,419,601

 

181,976,807

 

 

 

 

 

 

 

 

 

 

 

Basic net income per share

 

$

0.35

 

$

0.08

 

$

0.36

 

$

0.04

 

Diluted net income per share

 

$

0.35

 

$

0.08

 

$

0.35

 

$

0.04

 

 

The following options and unvested restricted shares, which could be potentially dilutive in future periods, were not included in the computation of diluted net income per share because the effect would have been anti-dilutive for the periods indicated:

 

 

 

For the Three Months Ended June 30,

 

For the Six Months Ended June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

Anti-dilutive shares

 

959,500

 

762,000

 

570,500

 

762,000

 

 

Note 11—Commitments and Contingencies

 

Lease Obligations

 

The Company leases office space in Denver, Colorado and Dickinson and Williston, North Dakota under separate operating lease agreements. The Denver, Colorado lease expires on April 30, 2016. The Dickinson and Williston, North Dakota leases expire on December 31, 2013 and May 31, 2013, respectively. Total rental commitments under non-cancelable leases for office space were $3.1 million at June 30, 2012.  The future minimum lease payments under these non-cancelable leases are as follows: $360,000 in 2012, $740,000 in 2013, $690,000 in 2014, $720,000 in 2015, and $630,000 in 2016.

 

Drilling Rigs

 

As of June 30, 2012, the Company was subject to commitments on six drilling rig contracts. One of the contracts expires in late 2012, four expire in 2013 and one expires in 2015. In the event of early termination under all of these contracts, the Company would be obligated to pay an aggregate amount of approximately $50.8 million as of June 30, 2012 as required under the varying terms of such contracts.

 

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Table of Contents

 

Pressure Pumping Services

 

As of June 30, 2012, the Company was subject to a commitment with a pressure-pumping service company providing 24-hour per day crew availability for 30 days per month, to be reconciled on a quarterly basis.  In the event of early contract termination, the Company would be obligated to pay approximately $36.0 million as of June 30, 2012 as required under the terms of the contract.

 

Guarantees of the Senior Notes

 

In November 2011 and May 2012, the Company issued Senior Notes due in 2019 in the amounts of $650.0 million and $156.0 million (including a $6.0 million premium on the issuance), respectively, which notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc. Kodiak Oil & Gas Corp., as the parent company, has no independent assets or operations. Such guarantee is full and unconditional, and the parent company has no other subsidiaries. In addition, there are no restrictions under the Senior Notes or the associated guarantees on the ability of the parent company to obtain funds from its subsidiary by dividend or loan. Finally, the parent company’s wholly-owned subsidiary does not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the parent company in the form of loans, advances or cash dividends by the subsidiary without the consent of a third-party.

 

The Company may issue additional debt securities in the future that the Company’s wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc., may guarantee. Any such guarantee is expected to be full, unconditional and joint and several. As stated above, the Company has no independent assets or operations nor does it have any other subsidiaries, and there are no significant restrictions on the ability of the Company to receive funds from the Company’s subsidiary through dividends, loans, and advances or otherwise.

 

Other

 

As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost.

 

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ITEM 2.     MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Forward-Looking Statements

 

The information discussed in this quarterly report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, changes in oil and gas production, the number of anticipated wells to be drilled after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

 

·                  unsuccessful drilling and completion activities and the possibility of resulting write-downs;

 

·                  capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;

 

·                  price volatility of oil and natural gas prices, and the effect that lower prices may have on our net income and stockholders’ equity;

 

·                  a decline in oil production or oil prices, and the impact of general economic conditions on the demand for oil and the availability of capital;

 

·                  geographical concentration of our operations;

 

·                  constraints imposed on our business and operations by our credit agreements and our ability to generate sufficient cash flows to repay our debt obligations;

 

·                  availability of borrowings under our credit agreements;

 

·                  termination fees related to drilling rig contracts and pressure pumping service contract;

 

·                  increases in the cost of drilling, completion and gas gathering or other costs of production and operations;

 

·                  our ability to successfully drill wells that produce oil in commercially viable quantities;

 

·                  failure to meet our proposed drilling schedule;

 

·                  financial losses and reduced earnings related to our commodity derivative agreements, and failure to produce enough oil to satisfy our commodity derivative agreements;

 

·                  adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;

 

·                  our current level of indebtedness and the effect of any increase in our level of indebtedness;

 

·                  hazardous, risky drilling operations and adverse weather and environmental conditions;

 

·                  limited control over non-operated properties;

 

·                  reliance on limited number of customers;

 

·                  title defects to our properties and inability to retain our leases;

 

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·                  incorrect estimates of proved reserves, the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs of properties that we acquire;

 

·                  our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage;

 

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

 

·                  constraints in the Williston Basin with respect to gathering, transportation and processing facilities and marketing;

 

·                  federal, state and tribal regulations and laws;

 

·                  risks in connection with potential acquisitions and the integration of significant acquisitions;

 

·                  impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;

 

·                  federal and state legislation and regulatory initiatives relating to hydraulic fracturing;

 

·                  integration of significant acquisitions, and difficulty managing our growth and the related demands on our resources;

 

·                  developments in the global economy;

 

·                  constraints imposed on our business and operations by our credit agreements and our Senior Notes and our ability to generate sufficient cash flows to repay our debt obligations;

 

·                  financing and interest rate exposure;

 

·                  effects of competition;

 

·                  effect of seasonal factors;

 

·                  lack of availability of drilling rigs, equipment, supplies, insurance, personnel and oil field services; and

 

·                  further sales or issuances of common stock and the volatility of the market for our shares.

 

Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in the section entitled “Risk Factors” included in our Annual Report on Form 10-K. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this report. Other than as required under securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

 

Overview

 

Kodiak is an independent energy company focused on the exploration, exploitation, acquisition and production of crude oil and associated natural gas in the Rocky Mountain region of the United States. We have developed an asset base of proved reserves, as well as a portfolio of development and exploratory opportunities on high-potential prospects with an emphasis on oil resource plays.  Our reserves and operations are primarily concentrated in the Williston Basin of North Dakota.  As of June 30, 2012, we owned an interest in approximately 234,000 gross (155,000 net) acres in the Williston Basin where our primary target is the middle Bakken and Three Forks formations.  As of June 30, 2012, we have an interest in 188 gross (81.6 net) producing wells in the Williston Basin.

 

Since late 2010, we have added significantly to our asset base in the Williston Basin through targeted acquisitions of properties within our core operating area.  We intend to expand our asset base by drilling and completing wells on our current lands, and we will continue to evaluate and invest in acquisitions, if and to the extent opportunities arise.

 

As of the date of this filing, we operate seven drilling rigs on our acreage.  The Company has a full-time, 24-hour-per-day completion crew.  We have utilized and will continue to engage a second completion crew to accelerate completion activity when required.

 

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Table of Contents

 

Recent Developments

 

Operational Update

 

During the second quarter of 2012, we focused on drilling and completing wells within our core acreage in the Williston Basin.  Wells within such core acreage generally have high working interests, are served by oil and gas gathering systems and can be drilled from multi-well pads.

 

During the first half of 2012, we drilled 28 gross (22.9 net) operated wells and completed 26 gross (20.7 net) operated wells.  We participated as non-operator in the drilling of 5 gross (1.8 net) wells and completed 8 gross (3.3 net) wells within the areas of mutual interest (“AMI”) area in Dunn County, North Dakota, and also participated in 25 gross (3.4 net) wells and completed 25 gross (3.1 net) non-operated excluding the AMI area.

 

During the second quarter of 2012, we drilled 14 gross (10.8 net) operated wells and completed 14 gross (12.7 net) operated wells.   Included in our wells completed during the second quarter are 4 gross (3.3 net) wells that were located in our recently acquired southern Williams county acreage.  These wells were the first wells to be both drilled and completed in this area by Kodiak using our drilling and completion techniques.  We are pleased with the performance of these wells and believe they demonstrate that this area is comparable to our core McKenzie county acreage, with similar high reservoir pressures, bottom-hole temperatures and depths.

 

During the second quarter of 2012, we continued our repair and remediation work on wells that encountered mechanical issues and successfully completed 4 gross (3.5 net) of these wells.  Two of the remediated wells were drilled by the Company in the fourth quarter of 2011 and two wells were assumed through previously announced acquisitions. Ultimately, we expect all other wells with mechanical issues to be remediated and to undergo completion operations.  We believe we have mitigated these mechanical issues predominantly through the use of cemented liners in new wells being drilled.  We are pleased with the success to date and intend to continue to use cemented liners in our completions.  Additionally, in the second quarter of 2012, we began employing a zipper fracturing technique on multi —well pad locations, which allow us to more rapidly complete the wells and establish cash flows.  Utilization of the zipper fracturing technique allows the simultaneous completion of two wells at one time by alternating perforation and pressure pumping operations.

 

During the second quarter of 2012, we drilled four water disposal wells.  With the addition of these wells and future water gathering systems, we anticipate that our operating costs, on a per unit basis, will improve.

 

We finished completion operations on 5 gross (3.4 net) operated wells in July 2012, and we expect to complete an additional 9 gross (7.5 net) operated wells during the remainder of the third quarter of 2012.

 

Generally, in the Williston Basin, oil and gas infrastructure continues to improve.  The majority of our wells in Dunn County are connected to pipeline infrastructure to transport oil, gas and water.  However, the ability to sell and process gas from these wells continues to be constrained due to gathering system pressure restrictions.  Some of these restrictions are being eliminated as additional capacity has been brought on-line and due to the addition of planned natural gas compression.  In McKenzie and Williams counties, the majority of our wells have been connected to gas pipelines and, in some cases, oil pipelines.  Pipeline construction continues at a steady pace, and we expect most of our wells to have pipeline access for oil by year-end 2012.  Sales of natural gas will continue to be dependent on processing plant capacity and the timing of connecting gas pipelines to newly completed wells.

 

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Table of Contents

 

The following summary provides a tabular presentation of our completion activities during the second quarter of 2012:

 

 

 

 

 

 

 

 

 

Production Volumes (BOE/d)

 

Well Name

 

WI / NRI
(%)

 

Formation

 

Length of
Lateral

 

IP 24 Hour
Test

 

30 Day
Cum

 

60 Day
Cum

 

Dunn County, ND

Skunk Creek 13-18-17-9H

 

100 / 82

 

Bakken

 

9,697

 

2,314

 

848

 

 

Skunk Creek 13-18-17-16H

 

100 / 82

 

Bakken

 

9,421

 

1,910

 

594

 

 

Williams and McKenzie Counties, ND

Thomas 154-98-15-33-28-2H

 

94 / 74

 

Bakken

 

9,277

 

4,021

 

1,559

 

1,277

 

Thomas 154-98-15-33-28-1H3

 

96 / 77

 

Three Forks

 

9,373

 

3,021

 

1,183

 

964

 

Koala 15-31-30-3H

 

97 / 78

 

Bakken

 

9,629

 

3,117

 

1,357

 

 

Koala 15-31-30-2H

 

97 / 78

 

Bakken

 

9,460

 

2,971

 

1,184

 

 

Koala 2-25-36-15H (1)

 

94 / 75

 

Bakken

 

9,177

 

2,709

 

1,394

 

 

P Peterson 155-99-2-15-22-15H

 

69 / 56

 

Bakken

 

9,491

 

2,130

 

 

 

P Peterson 155-99-2-15-22-15H3

 

69 / 56

 

Three Forks

 

8,977

 

2,569

 

 

 

Smokey 16-20-17-2H3

 

97 / 76

 

Three Forks

 

9,284

 

1,620

 

 

 

Smokey 16-20-32-15H

 

96 / 76

 

Bakken

 

10,020

 

2,440

 

 

 

Smokey 16-20-32-16H

 

96 / 76

 

Bakken

 

9,080

 

2,362

 

 

 

Smokey 15-22-34-15H (1)

 

78 / 63

 

Bakken

 

8,914

 

2,858

 

 

 

Paulson 49-1H (1)

 

82 / 64

 

Bakken

 

9,374

 

554

 

 

 

Non-Operated: Dunn County, ND

FBIR Goes Everywhere 31X-11

 

50 / 41

 

Bakken

 

9,350

 

Well on confidential status

 

FBIR Grinnell 41X-1

 

31 / 25

 

Bakken

 

10,160

 

Well on confidential status

 

FBIR Lawrence 24X-26

 

47 / 39

 

Bakken

 

9,520

 

Well on confidential status

 

FBIR Youngbear 31X-9

 

38 / 31

 

Bakken

 

9,175

 

Well on confidential status

 

 


(1) Indicates remediated well with successful liner patch

 

Regulatory Matters

 

On April 17, 2012, the Environmental Protection Agency issued final rules that subject oil and natural gas production, processing, transmission and storage operations within federal regulatory jurisdiction to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs. The Environmental Protection Agency rules include standards under the New Source Performance Standards for completions of hydraulically fractured wells.

 

The final rules establish a phase-in period that will ensure that manufacturers have time to make and broadly distribute the required emissions reduction technology.  During the first phase, until January 1, 2015, owners and operators must either flare their emissions or use emissions reduction technology called “green completions”. The finalized rules also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. We are currently evaluating the effect these rules will have on ourbusiness and financial condition.

 

On May 11, 2012, the Bureau of Land Management published proposed rules to regulate hydraulic fracturing on federal public lands and Indian lands. The proposed rules would address well stimulation operations, including requiring agency approval for certain activities, and would require the disclosure of well stimulation fluids, as well as address issues relating to flowback water. If adopted, these rules may require changes to our operations, lead to operational delays and/or increased operating costs, and result in greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. The rules are expected to be finalized by the end of 2012. We are currently evaluating the effect these proposed rules would have on our business and financial condition.

 

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Table of Contents

 

Capital Resources and Liquidity

 

2012 Capital Expenditures Budget

 

Our 2012 capital expenditure budget of $585.0 million (exclusive of $642.9 million used to fund our January 2012 acquisition) is subject to various factors, including market conditions, oilfield services and equipment availability, commodity prices and drilling results.  During the first half of 2012, we incurred capital expenditures of approximately $335.5 million related to drilling and completion operations, and related infrastructure and leasehold acquisition (exclusive of our January 2012 acquisition and capitalized interest of $24.5 million).

 

During the six months ended June 30, 2012, we spent $253.9 million on our operated properties, $30.3 million on non-operated properties in our Dunn County AMI, $7.4 million on leasehold expenditures and $5.1 million for water disposal facilities.  We anticipate spending approximately $300.0 million in the second half of the year on these properties.

 

We have incurred capital expenditures of $38.8 million for the six months ended June 30, 2012, related to non-operated interests outside our Dunn County AMI. The costs related to such non-operated properties are difficult to project because the timing of the operations is not under our control.  Most of this activity in the first half of 2012 was associated with the properties acquired in January 2012.  A significant portion of the non-operated acreage in this area is now held by production and we expect reduced drilling activity.  Further, we participated in one well in which we incurred significant expenditures to technically evaluate the producing intervals.  As a result, we expect our net expenditures on these activities to be lower in the second half of 2012 as compared to costs incurred to date.  We estimate that total capital expenditures for this non-operated activity could be as much as $50.0 million for the entire year of 2012.

 

Our rig count will be in a direct relationship to oil prices and the economics derived from our wells.  Recently, we have decreased our total drilling days and with this increased efficiency, we believe we can reduce our expected rig count without affecting our well count. While we continue to evaluate our capital expenditure program for the second half of 2012, we currently expect to maintain our operated rig count at seven rather than the eight as originally budgeted.  This decrease will partially offset the increase in our capital expenditures from unbudgeted, non-operated activities.

 

Senior Notes

 

In November 2011, we issued at par $650.0 million principal amount of 8.125% Senior Notes due December 1, 2019.  In May 2012, we issued an additional $150.0 million aggregate principal amount of our Senior Notes at 104.0% of par, resulting in a $6.0 million premium on the issuance.  The interest on our Senior Notes is payable on June 1 and December 1 of each year. For further discussion regarding the Senior Notes, please refer to Note 4—Long-Term Debt under Item 1 in this Quarterly Report.

 

Derivative Instruments

 

We utilize various derivative instruments in connection with anticipated crude oil sales to minimize