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

 

KODIAK OIL & GAS CORP.

 

INDEX

 

PART 1—FINANCIAL INFORMATION

3

ITEM 1.

FINANCIAL STATEMENTS (UNAUDITED)

3

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

22

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

36

ITEM 4.

CONTROLS AND PROCEDURES

37

 

 

 

PART II—OTHER INFORMATION

38

ITEM 1.

LEGAL PROCEEDINGS

38

ITEM 1A.

RISK FACTORS

38

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

38

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

38

ITEM 4.

MINE SAFETY DISCLOSURES

38

ITEM 5.

OTHER INFORMATION

38

ITEM 6.

EXHIBITS

38

SIGNATURES

39

 

2



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

 

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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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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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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.

 

7



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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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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

 

 

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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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Table of Contents

 

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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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 the impact of product price fluctuations and ensure cash flow for future capital needs. Currently, we utilize swaps and “no premium” collars. Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. If actual commodity prices are higher than the fixed or ceiling prices in our derivative instruments, our cash flows will be lower than if we had no derivative instruments. Conversely, if actual commodity prices are lower than the fixed or floor prices in our derivative instruments, our cash flows will be higher than if we had no derivative instruments.

 

Working Capital

 

Our working capital was $20.1 million at June 30, 2012, as compared to a deficit of $56.9 million at March 31, 2012 and a positive $72.8 million at December 31, 2011. We expect to maintain low cash and cash equivalent balances going forward, as we typically use available funds to reduce any balance on our credit facility. Short-term liquidity needs are satisfied by borrowings under our credit facility. Because of this, and since our principal source of operating cash flows (proved reserves to be produced in future years) is not considered working capital, we may have low or negative working capital at any given time.

 

Sources of Capital

 

Our 2012 drilling program is designed to provide flexibility in identifying suitable well locations and in the timing and size of capital investment. We anticipate funding the remainder of our 2012 capital program and meeting our debt service requirements primarily through operating cash flows and credit expected to be available through our borrowing base facility. Following is a discussion of each of these expected sources of cash:

 

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Cash flow from operations.  We expect our cash flow from operations to continue to increase commensurate with our anticipated increase in production.  Our production has increased to 1,155.4 MBOE for the three months ended June 30, 2012 as compared to 962.6 MBOE for three months ended March 31, 2012.   This increase is directly related to our successful operations as we have developed our properties.  If we are able to drill and complete our wells as anticipated and they produce at rates similar to those generated by our existing wells, we would expect our production rates and operating cash flows to continue to increase as we execute our 2012 program.

 

The increase in cash flow during the second quarter of 2012, related to production growth, was partially impacted by a decrease in prices received for oil sales.  During the second quarter of 2012, the net price received for oil sales was $78.93 as compared to $87.43 during the first quarter 2012.   Based on current and forward crude oil prices, our cash flow from operations would be negatively impacted by these lower prices.  To a certain extent, we have mitigated this price volatility through the use of derivative instruments as discussed previously.

 

Credit Facility.  As of June 30, 2012, our borrowing base was $225.0 million with a maximum credit amount of $750.0 million and a maturity date of November 14, 2016.  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.   Redetermination of the borrowing base occurs semi-annually, on April 1 and October 1.  The ability to maintain and increase this facility and borrow additional funds is dependent on a number of variables, including our proved reserves, and assumptions regarding the price at which oil and natural gas can be sold. Further, we expect that our borrowing base will increase with the addition of proved properties as a result of our ongoing drilling and completion activities.  We are subject to restrictive covenants under the credit facility.  For further details on our credit facility please refer to Note 4—Long-Term Debt under Item 1 in this Quarterly Report.

 

We expect that our cash flows from operations, cash on hand and the availability under our revolving credit facility will be sufficient to meet our remaining 2012 capital expenditures budget, our obligations under our Senior Notes and other contractual commitments (please refer to Note 11—Commitments and Contingencies under Item 1 in this Quarterly Report). If our existing and potential sources of liquidity are not sufficient to satisfy such commitments and to undertake our currently planned expenditures, we believe that we have the flexibility in our commitments to alter our drilling program.  Since we operate the majority of our acreage, we have the ability to adjust our drilling schedule to reflect a change in commodity price or oil field service environment.   In the event we had to reduce the level of activity, we may incur termination fees depending on the timing and contractual requirements of our drilling rig and completions services contracts.   However, the majority of our acreage is currently producing and the remaining acreage could be held by production within the primary term of the lease, even with a reduced number of drilling rigs.

 

Historically, we have financed our operations, property acquisitions and other capital investments from the proceeds of offerings of our equity and debt securities. We currently have on file with the SEC a universal shelf registration statement to allow us to offer an indeterminate amount of securities in the future. Under the registration statement, we may offer from time to time debt securities, common stock, preferred stock, warrants and other securities or any combination of such securities in amounts, prices and on terms announced when and if the securities are offered. The specifics of any future offerings, along with the use of proceeds of any securities offered, would be described in detail in a prospectus supplement at the time of any such offering.

 

Cash Flow Analysis

 

The following is a summary of our change in cash and cash equivalents for the six month periods as of June 30, 2012 and June 30, 2011 (in thousands):

 

 

 

Six Months Ended June 30,

 

Period to period

 

 

 

2012

 

2011

 

change

 

Net cash provided by operating activities

 

$

89,525

 

$

23,505

 

$

66,020

 

Net cash used in investing activities

 

(880,843

)

(149,886

)

(730,957

)

Net cash provided by financing activities

 

723,210

 

75,628

 

647,582

 

Decrease in cash and cash equivalents

 

$

(68,108

)

$

(50,753

)

$

(17,355

)

 

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Net cash provided by operating activities.  The key components of our net cash provided by operating activities are our production volumes (in particular, our crude oil sales volumes) and commodity prices (in particular, crude oil prices).  For the first six months of 2012 as compared to the same period in 2011, our net cash provided by operating activities increased by $66.0 million, primarily from increased crude oil sales volumes attributable to our successful drilling and completions in our core Bakken and Three Forks formations in the Williston basin.  However, the increase in our net cash provided by operations was negatively impacted by the decrease in crude oil prices for the first six months of 2012 as compared to the same period in 2011.  Refer to the Operating Results section below for further analysis on the changes in the net cash provided by operating activities.

 

Net cash used in investing activities.  The primary driver in our net cash used for investing activities is our capital expenditure budget, which consists of both our ongoing drilling and completion expenditures and our acquisition expenditures.  For the first six months of 2012 as compared to the same period in 2011, our net cash used in investing activities increased by $731.0 million.  This increase is primarily attributed to our January 2012 acquisition, which required $588.4 million in cash, and secondarily, to our significantly increased capital expenditures for drilling and completions during the first six months of 2012 as compared to the same period in 2011.

 

Net cash provided by financing activities.  For the first six months of 2012 as compared to the same period in 2011, our net cash provided by financing activities increased by $647.6 million.  This was a result of our receipt from escrow of $670.6 million, from our November 2011 Senior Note offering ($588.4 million of which was used to fund our January 2012 acquisition and $100.0 million of which was used to repay our second lien credit agreement) and the receipt of $151.8 million net proceeds from our May 2012 Senior Note offering.

 

Our Properties

 

Williston Basin (155,000 net acres)

 

Our Williston Basin acreage is located primarily in Dunn, McKenzie and Williams counties, of North Dakota. Our primary geologic target in the Williston Basin is the Bakken pool. In the Bakken pool, our primary objective is the dolomitic, sandy interval between the two Bakken shales at an approximate vertical depth of 10,300-11,300 feet and the Three Forks Formation immediately below the lower Bakken shale.

 

We have focused our operations in an area that we believe has higher reservoir pressure, a high degree of thermal maturity, and is prospective for both the middle Bakken and the Three Forks formations. Based on recent drilling results, along with internal and third-party reserve engineering analysis, we expect wells in this area to have economic ultimate recoveries (“EUR’s”) that range from 450 to over 900 thousand barrels of oil equivalent (“MBOE”).

 

Other important aspects of our drilling program in this core Williston Basin area include the following:

 

·                  Based upon our exploration efforts from 2009 through mid-2012, we believe that the internal rate of return of the longer 10,000 foot laterals is higher than we were achieving with our shorter laterals of 5,000 feet or less. Although utilizing long laterals is more expensive, we estimate that the additional costs of drilling the longer lateral and adding more fracture stimulation stages is offset by the associated incremental increase in oil production.

 

·                  We have continued to drill on pads with two to four wells. We believe that, in future years, the number of wells drilled from each pad could increase. The significance of pad drilling is primarily directed to mobilization and demobilization of our drilling rigs which reduces costs and minimizes the impact on the surface locations. As the industry is facing a shortage of services, the use of pad drilling has become even more important as it lowers the number of moves required between wells, eliminating the need for trucks to move the equipment, a service that is in high demand. Furthermore, we have seen efficiencies in our completion work as we eliminate mobilization and demobilization time for our pressure pumping company, allowing it more efficient use of its time. Additionally, the use of pads allows multiple wells to share infrastructure and service personnel. In 2012 and forward, we plan to drill all wells from two-well to four-well pads.

 

·                  We have completed wells across our core acreage with separation of approximately 1,300 feet or less. With the data obtained during the stimulation procedures, we experienced very little communication between formations and we believe that this spacing can be used as we move to development. Based upon the thickness of the middle Bakken in our prospect areas, we believe the results of our completion work support a density of up to four middle Bakken wells within many of our drilling units.

 

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Table of Contents

 

·                  Completion techniques have been and will continue to be evaluated with the expectation of gaining efficiencies on our completion methods as more data becomes available. Early results from our completion of wells in the Three Forks Formation are somewhat consistent with the results of our middle Bakken wells and indicative of the potential of the Formation. Production results have shown little communication with the middle Bakken reservoir, suggesting separate reservoirs. All of these wells were positioned less than 700 feet horizontally from a middle Bakken well with approximately 65 feet of vertical separation. This work has continued to support our belief that potentially three to four Three Forks wells can be completed in a drilling unit below the middle Bakken wells.

 

·                  Our leasehold is largely contiguous and by virtue of our high working interest and operatorship, we can control the development pace and location of surface facilities. We believe this strategy, combined with pad drilling and long laterals, will maximize the efficiency of our drilling program and minimize the infrastructure required to connect our wells to sales pipelines. As a result, we are able to plan our locations to minimize the number of wells required to hold our acreage by establishing production within the primary terms of our leases. Once all of our acreage is held by production, we expect to gain efficiencies as this will allow us to develop acreage in a more methodical approach.

 

·                  Most of our core Williston Basin area is served by third-party oil and gas gathering systems. The majority of our wells are connected to or are in the process of being connected to oil and gas pipelines. However, our gas sales continue to be limited by plant capacity needed to process the gas and strip out the high liquids content. Moving oil and gas through pipelines eliminates trucking costs and associated surface disturbance, and mitigates weather-related production interruptions. As the capacity of natural gas pipelines and related processing facilities increases, we should be able to capture additional revenue generated from the sale of associated natural gas that is currently flared.

 

·                  In Dunn County, we have progressed in connecting our wells to third-party pipelines that transport water directly to disposal facilities. In 2012, we have drilled water disposal wells on several of our producing areas outside of Dunn County and are constructing water gathering systems.

 

Mid-Year 2012 Proved Oil and Gas Reserves

 

The following table sets forth summary information regarding our estimated proved reserves as of June 30, 2012. We determined the natural gas equivalent of oil by using a conversion ratio of six Mcf of natural gas to one barrel of oil.

 

 

 

 

 

 

 

Net Remaining Oil

 

Net Remaining Gas

 

Net Remaining Oil

 

Reserve Category

 

Gross Wells

 

Net Wells

 

(MBbls)

 

(MMcf)

 

Equivalent (MBOE)

 

Proved Developed Reserves

 

188

 

81.6

 

23,750.0

 

24,712.4

 

27,868.7

 

Proved Undeveloped Reserves

 

148

 

85.5

 

36,601.2

 

33,739.1

 

42,224.3

 

Total Combined Proved Reserves

 

336

 

167.1

 

60,351.2

 

58,451.5

 

70,093.0

 

 

For the six months ended June 30, 2012, we engaged Netherland, Sewell & Associates, Inc., an independent, third-party reserves engineer, to audit our internally prepared estimated proved reserves.  Estimated proved reserves at June 30, 2012, were 70.1 million barrels of oil equivalent (“MMBOE”), an increase of 36% over pro forma year-end 2011, which includes our properties acquired in early 2012. The Company’s proved reserves were 86% oil, and 14% natural gas at June 30, 2012, compared to 89% oil and 11% natural gas at pro forma year-end 2011. Approximately 40% of the mid-year total proved reserves are categorized as proved developed producing and approximately 60% are classified as proved undeveloped.  Reserve growth for the first half of 2012 was driven by the Company’s drilling program in the Williston Basin targeting the Middle Bakken and Three Forks formations.

 

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Table of Contents

 

Our Leasehold

 

As of June 30, 2012, we had several hundred lease agreements representing approximately 268,000 gross and 166,000 net acres primarily in the Williston and Green River Basins. The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases:

 

 

 

Undeveloped Acreage(1)

 

Developed Acreage(2)

 

Total Acreage

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Green River Basin

 

 

 

 

 

 

 

 

 

 

 

 

 

Wyoming

 

25,021

 

5,689

 

1,700

 

953

 

26,721

 

6,642

 

Colorado

 

5,445

 

3,680

 

1,894

 

1,280

 

7,339

 

4,960

 

Williston Basin

 

 

 

 

 

 

 

 

 

 

 

 

 

Montana

 

 

 

3,452

 

2,084

 

3,452

 

2,084

 

North Dakota

 

113,647

 

76,370

 

117,172

 

76,371

 

230,819

 

152,741

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Acreage Totals

 

144,113

 

85,739

 

124,218

 

80,688

 

268,331

 

166,427

 

 


(1)          Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage includes proved reserves.

 

(2)          Developed acreage is the number of acres that are allocated or assignable to producing wells or wells capable of production.

 

We believe we have satisfactory title, in all material respects, to substantially all of our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Substantially all of our proved oil and natural gas properties are pledged as collateral for borrowings under our credit facility.

 

Substantially all of the leases summarized in the preceding table will expire at the end of their respective primary terms unless (i) the existing lease is renewed; (ii) we have obtained production from the acreage subject to the lease prior to the end of the primary term, in which event the lease will remain in effect until the cessation of production; or (iii) it is contained within a federal unit. The following table sets forth the gross and net acres of undeveloped land subject to leases that will expire during the current year and the following three years and have no options for renewal or are not included in federal units:

 

 

 

Expiring Acreage

 

Year Ending

 

Gross

 

Net

 

December 31, 2012

 

19,807

 

11,221

 

December 31, 2013

 

30,395

 

20,871

 

December 31, 2014

 

34,540

 

19,538

 

December 31, 2015

 

12,572

 

4,782

 

Total

 

97,314

 

56,412

 

 

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Table of Contents

 

Operating Results

 

Production and Sales Volumes, Average Sales Prices, and Production Costs

 

The Bakken is the only field (as such term is used within the meaning of applicable regulations of the SEC) that contains more than 15% of our total proved reserves. At December 31, 2011, this field contained 99% of our total proved reserves, nearly all of which are located in Williams, Dunn and McKenzie Counties. The following table discloses our oil and gas production and sales volumes from the Bakken field, from our other fields combined and in total, for the periods indicated:

 

 

 

For the Three Months Ended June 30,

 

For the Six Months Ended June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Sales Volume (Bakken):

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

1,039,382

 

217,583

 

1,913,538

 

365,687

 

Gas (Mcf)

 

663,061

 

81,848

 

1,156,654

 

102,413

 

 

 

 

 

 

 

 

 

 

 

Sales Volume (Other):

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

4,472

 

6,172

 

8,892

 

15,463

 

Gas (Mcf)

 

6,040

 

5,274

 

16,623

 

46,913

 

 

 

 

 

 

 

 

 

 

 

Sales Volume (Total):

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

1,043,854

 

223,755

 

1,922,430

 

381,150

 

Gas (Mcf)

 

669,101

 

87,122

 

1,173,277

 

149,326

 

Sales volumes (BOE)

 

1,155,370

 

238,275

 

2,117,976

 

406,038

 

Natural Gas flared (Mcf) (1):

 

687,880

 

143,495

 

1,324,928

 

231,949

 

 

 

 

 

 

 

 

 

 

 

Total production volume (Total):

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

1,047,682

 

222,907

 

1,936,006

 

379,534

 

Gas (Mcf)

 

1,356,981

 

230,617

 

2,498,205

 

381,275

 

Production volumes (BOE)

 

1,273,846

 

261,343

 

2,352,373

 

443,080

 

 


(1)     Includes production of natural gas that is not included in our sales volumes.  All flared gas is related to the Bakken field.

 

Sales prices received, and production costs per sold BOE for the three and six months ended June 30, 2012 and 2011 are summarized in the following table:

 

 

 

For the Three Months Ended June 30,

 

For the Six Months Ended June 30,

 

 

 

2012

 

2011

 

2012

 

2011

 

 

 

 

 

 

 

 

 

 

 

Sales Price:

 

 

 

 

 

 

 

 

 

Oil ($/Bbls)

 

$

78.93

 

$

95.72

 

$

82.81

 

$

90.35

 

Gas ($/Mcf) (1)

 

$

5.05

 

$

7.99

 

$

5.54

 

$

6.76

 

 

 

 

 

 

 

 

 

 

 

Commodity Price Risk Management Activities ($/Sales BOE):

 

 

 

 

 

 

 

 

 

Realized gain (loss)

 

$

3.35

 

$

(4.17

)

$

(0.40

)

$

(3.29

)

 

 

 

 

 

 

 

 

 

 

Production costs ($/Sales BOE):

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

5.60

 

$

7.46

 

$

6.26

 

$

6.84

 

Production and property taxes

 

$

7.80

 

$

10.33

 

$

8.27

 

$

9.80

 

Gathering, transportation, marketing

 

$

1.49

 

$

0.82

 

$

1.76

 

$

0.61

 

DDA

 

$

29.59

 

$

19.02

 

$

28.56

 

$

20.32

 

G&A

 

$

7.05

 

$

17.58

 

$

7.57

 

$

21.94

 

Stock-based compensation

 

$

2.30

 

$

3.98

 

$

2.40

 

$

6.12

 

 


(1)                      Average gas price received at the wellhead includes proceeds from natural gas liquids under percentage of proceeds contracts.

 

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

 

Oil sales revenues.  Oil sales revenues increased by $61.0 million to $82.4 million for the three months ended June 30, 2012, as compared to oil sales of $21.4 million for the same period in 2011. Our oil sales volume increased 367% to 1,043.9 thousand barrels (MBbls) in the first quarter of 2012 as compared to 223.8 MBbls in the second quarter of 2011. The average price we realized on the sale of our oil was $78.93 per barrel in the 2012 period compared to $95.72 per barrel in 2011. The volume increase is due to the development of our Bakken properties as well as the June 2011, October 2011 and January 2012 property acquisitions.  Of the 820.0 MBbls increase in sales volume, 199.9 MBbls is related to producing wells acquired in these acquisitions and 620.1 MBbls is attributed to our ongoing development of our legacy properties and undeveloped acreage.  Overall, 106.2% of the increase in oil sales revenue was attributed to increased volumes and negative 6.2% was attributed to the decrease in crude oil prices received.

 

Natural gas sales revenues.  Natural gas sales revenues increased by $2.7 million to $3.4 million for the three months ended June 30, 2012, as compared to natural gas sales revenues of $696,000 for the same period in 2011. Natural gas sales volumes increased to 669.1 million cubic feet (MMcf) in the second quarter of 2012 compared 87.1 MMcf in the same period in 2011. The average price we realized on the sale of our natural gas was $5.05 per Mcf in the 2012 period compared to $7.99 per Mcf in 2011.  Overall, 109.6% of the increase in natural gas sales revenue was attributed to increased volumes and negative 9.6% was attributed to the decrease in natural gas prices received. The volume increase is due to the development of our Bakken properties as well as the June 2011, October 2011 and January 2012 property acquisitions.  Of the 582.0 MMcf increase in sales volume, 161.5 MMcf is related to producing wells acquired in these acquisitions and 420.5 MMcf is attributed to our ongoing development of our legacy properties and acquired undeveloped acreage.  Although gas from certain wells continues to be flared, during 2011 and continuing into 2012, we connected the majority of our wells to gas pipelines which allowed us to capture the related sales revenue.  As these third-parties expand their processing capacity we expect additional gas volumes to be gathered, processed and sold.

 

Oil and gas production expense.  Our production expense increased by $12.8 million to $17.2 million for the quarter ended June 30, 2012 as compared to $4.4 million for the same period in 2011. The increase is due to a $6.6 million increase in production taxes, a $4.7 million increase in lease operating expenses (“LOE”) and a $1.5 million increase in gathering, transportation and marketing expense. The production tax increase is attributable to increased revenue as it is calculated as a fixed percentage of sales revenue. LOE increased year over year due to a higher number of wells that we operate or participate in. On a per unit basis, LOE decreased from $7.46 per barrel sold in 2011 to $5.60 in 2012. The largest component of our lease operating expense continues to be the disposal of produced water.  To date, the majority of water has been transported by truck to third-party disposal facilities.  Availability of both trucking and third party disposal facilities has improved, which has decreased our LOE on a per unit basis.

 

To further reduce water disposal costs, in 2012, we have drilled water disposal wells on several of our producing areas and are constructing water gathering systems where appropriate. As we connect existing and future wells to these water gathering systems, we expect our LOE to decrease on a per unit basis.

 

Depletion, depreciation, amortization and abandonment liability accretion (“DD&A”) expense.  Our depletion, depreciation, amortization and abandonment liability accretion expense increased by $29.7 million to $34.2 million for the three months ended June 30, 2012, from $4.5 million for the same period in 2011. This increase is due to increased volumes sold in 2012 as sales increased by approximately 917,000 BOE over the same period. On a per unit basis, DD&A increased from $19.02 per barrel sold in the second quarter of 2011 to $29.59 per barrel sold in 2012. This increase in DD&A rate was primarily the result of the allocation of the purchase price to proved properties related to our acquisitions in October 2011 and January 2012. Acquired proved reserves are valued at fair market value on the date of acquisition, which contributes to a higher amortization base, as compared to our historical cost of acquiring leasehold and developing our properties. To date, the fair value of our acquired proved reserves has been higher than our historical cost of developing our properties even though the resulting EUR’s are equivalent. Therefore, the increase in the ratio of costs subject to amortization to the reserves acquired is greater than our internally developed properties. We believe that, although initially these acquisitions increase our DD&A rate per BOE over the development of the acquired properties, the resulting rates will decline with infill drilling and the addition of the related reserves.

 

General and administrative (“G&A”) expense.  G&A expense increased by $3.9 million to $8.1 million for the quarter ended June 30, 2012, from $4.2 million for the same period in 2011. This increase is primarily due to the growth in personnel and related costs as we have expanded our operational activities related to the Bakken development. Total employees increased to 100 at June 30, 2012, from 52 at June 30, 2011.

 

Our G&A expense includes the non-cash expense for share-based compensation for stock options and restricted stock unit grants under our 2007 Stock Incentive Plan, as amended. For the three months ended June 30, 2012, this expense was $2.7 million as compared to $948,000 for the same period in 2011.

 

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Operating income.  Our operating income was approximately $26.2 million for the quarter ended June 30, 2012, as compared to approximately $9.0 million for the quarter ended June 30, 2011. This increase in operating income is attributed to our recent acquisitions, our on-going successful completions of wells in our Bakken play which was partially offset by the decline in crude oil price from the second quarter of 2011 to the second quarter of 2012.

 

Gain on commodity price risk management activities.  Primarily due to the decrease in NYMEX crude oil prices at June 30, 2012 as compared to March 31, 2012, we incurred a total gain on our risk management activities of $95.6 million for the three months ended June 30, 2012 compared to a gain of $4.9 million for the comparable period in 2011. This gain is a result of our hedging program used to mitigate our exposure to commodity price fluctuations. This gain was comprised of approximately $3.9 million of realized gains for transactions that were settled during the second quarter of 2012 and $91.7 million of unrealized gains for the mark-to-market of forward transactions. The unrealized gain is a non-cash adjustment for the value of our risk management transactions at June 30, 2012. These transactions will continue to change in value until the transactions are settled and we will likely add to our hedging program. Therefore, we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time.

 

Interest income (expense), net.  For the three months ended June 30, 2012, we recognized interest expense of approximately $3.5 million, as compared to $0 for the same period in 2011. Included in interest expense was $690,000 and $200,000 in amortization of deferred financing costs for the three months ended June 30, 2012 and 2011, respectively.  Additionally, we capitalized interest costs of $12.0 million and $1.1 million for the three months ended June 30, 2012 and 2011, respectively.

 

Income tax expense.  As discussed in Note 5—Income Taxes under Item 1 in this Quarterly Report, at March 31, 2012, we had a full valuation allowance against our U.S. and Canada net deferred tax assets.  During the second quarter of 2012, we concluded that it was appropriate to reverse the U.S. valuation allowance, but retained a full valuation allowance on our Canadian net deferred tax assets.  We recognized a net deferred tax liability and income tax expense of $25.9 million as of June 30, 2012 and for the three months then ended, respectively.  For the three months ended June 30, 2011, there was no income tax expense or benefit recognized as we had a full valuation allowance on our U.S. and Canadian net deferred tax assets.

 

Net income.  Our net income was $93.1 million for the quarter ended June 30, 2012, as compared to $14.0 million for the quarter ended June 30, 2011. Our 2012 net income was positively impacted by our gain on commodity price risk management activities and higher operating income.  However, these increases were negatively impacted by increased DD&A, G&A, interest expense, and income tax expense.

 

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

 

Oil sales revenues.  Oil sales revenues increased by $124.8 million to $159.2 million for the six months ended June 30, 2012, as compared to oil sales of $34.4 million for the same period in 2011. Our oil sales volume increased 404% to 1,922.4 MBbls for the six months ended June 30, 2012, as compared to 381.2 MBbls for the same period in 2011. The average price we realized on the sale of our oil was $82.81 per barrel in the 2012 period compared to $90.35 per barrel in 2011. The volume increase is due to the development of our Bakken properties as well as the June 2011, October 2011 and January 2012 property acquisitions.  Of the 1,541.3 MBbls increase in sales volume, 422.7 MBbls is related to producing wells acquired in these acquisitions and 1,118.6 MBbls is attributed to our ongoing development of our legacy properties and the acquired undeveloped acreage.  Overall, 102.3% of the increase in oil sales revenue was attributed to increased volumes and negative 2.3% was attributed to the decrease in crude oil prices received.

 

Natural gas sales revenues.  Natural gas sales revenues increased by $5.5 million to $6.5 million for the six months ended June 30, 2012, as compared to natural gas sales revenues of $1.0 million for the same period in 2011. Natural gas sales volumes increased to 1,173.3 MMcf in the second quarter of 2012 compared 149.3 MMcf in the same period in 2011. The average price we realized on the sale of our natural gas was $5.54 per Mcf in the 2012 period compared to $6.76 per Mcf in 2011.  Overall, 103.3% of the increase in natural gas sales revenue was attributed to increased volumes and negative 3.3% was attributed to the decrease in natural gas prices received. The volume increase is due to the development of our Bakken properties as well as the June 2011, October 2011 and January 2012 acquisitions.  Of the 1,024.0 MMcf increase in sales volume, 364.6 MMcf is related to producing wells acquired in these acquisitions and 659.4 MMcf is attributed to our ongoing development of our legacy properties and acquired undeveloped acreage.  Although gas from certain wells continues to be flared, during 2011 and continuing into 2012, we connected the majority of our wells to gas pipelines which allowed us to capture the related sales revenue.  As these third-parties expand their processing capacity we expect additional gas volumes to be gathered, processed and sold.

 

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Oil and gas production expense.  Our production expense increased by $27.5 million to $34.5 million for the six months ended June 30, 2012 as compared to $7.0 million for the same period in 2011. The increase is due to a $13.5 million increase in production taxes, a $10.5 million increase in lease operating expenses and a $3.5 million increase in gathering, transportation and marketing expense. The production tax increase is attributable to increased revenue as it is calculated as a fixed percentage of sales revenue. LOE increased year over year due to a higher number of wells that we operate or participate in. On a per unit basis, LOE decreased from $6.84 per barrel sold in 2011 to $6.26 in 2012. The largest component of our lease operating expense continues to be the disposal of produced water.  To date, the majority of water has been transported by truck to third-party disposal facilities.  Availability of both trucking and third party disposal facilities has improved, which has decreased our LOE on a per unit basis.

 

To further reduce water disposal costs, in 2012, we have drilled water disposal wells on several of our producing areas and are constructing water gathering systems where appropriate. As we connect existing and future wells to these water gathering systems, we expect our LOE to decrease on a per unit basis.

 

Depletion, depreciation, amortization and abandonment liability accretion (“DD&A”) expense.  Our depletion, depreciation, amortization and abandonment liability accretion expense increased by $52.2 million to $60.5 million for the six months ended June 30, 2012, from $8.3 million for the same period in 2011. This increase is due to increased volumes sold in 2012 as sales increased by approximately 1.7 million BOE over the same period. On a per unit basis, DD&A increased from $20.32 per barrel sold in the second quarter of 2011 to $28.56 per barrel sold in 2012. This increase in DD&A rate was primarily the result of the allocation of the purchase price to proved properties related to our acquisitions in October 2011 and January 2012. Acquired proved reserves are valued at fair market value on the date of acquisition, which contributes to a higher amortization base, as compared to our historical cost of acquiring leasehold and developing our properties. To date, the fair value of our acquired proved reserves has been higher than our historical cost of developing our properties even though the resulting EUR’s are equivalent. Therefore, the increase in the ratio of costs subject to amortization to the reserves acquired is greater than our internally developed properties. We believe that, although initially these acquisitions increase our DD&A rate per BOE over the development of the acquired properties, the resulting rates will decline with infill drilling and the addition of the related reserves.

 

General and administrative (“G&A”) expense.  G&A expense increased by $7.1 million to $16.0 million for the six months ended June 30, 2012, from $8.9 million for the same period in 2011. This increase is primarily due to the growth in personnel and related costs as we have expanded our operational activities related to the Bakken development. Total employees increased to 100 at June 30, 2012, from 52 at June 30, 2011.

 

Our G&A expense includes the non-cash expense for share-based compensation for stock options and restricted stock unit grants under our 2007 Stock Incentive Plan. For the six months ended June 30, 2012, this expense was $5.1 million as compared to $2.5 million in 2011.

 

Operating income.  Our operating income was approximately $54.7 million for the six months ended June 30, 2012, as compared to approximately $11.3 million for the six months ended June 30, 2011. This increase in operating income is attributed to our recent acquisitions, our on-going successful completions of wells in our Bakken play which was partially offset by the decline in crude oil price from the first six months of 2011 to the first six months of 2012.

 

Gain on commodity price risk management activities.  Primarily due to the decrease in NYMEX crude oil prices at June 30, 2012 as compared to December 31, 2011, we incurred a total gain on our risk management activities of $72.2 million for the six months ended June 30, 2012 compared to a loss of $4.8 million for the comparable period in 2011. This gain for the six months ended June 30, 2012 is a result of our hedging program used to mitigate our exposure to commodity price fluctuations. This gain was comprised of approximately $852,000 of realized losses for transactions that were settled during the first half of 2012 and $73.1 million of unrealized gains for the mark-to-market of forward transactions. The unrealized gain is a non-cash adjustment for the value of our risk management transactions at June 30, 2012. These transactions will continue to change in value until the transactions are settled and we will likely add to our hedging program. Therefore, we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time.

 

Interest income (expense), net.  For the six months ended June 30, 2012, we recognized interest expense of approximately $8.2 million, as compared to interest expense of $0 for the same period in 2011. Included in interest expense was $1.3 million and $387,000 in amortization of deferred financing costs for the six months ended June 30, 2012 and 2011, respectively.  Additionally, we capitalized interest costs of $24.5 million and $2.2 million for the six months ended June 30, 2012 and 2011, respectively.

 

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Income tax expense.  As discussed in Note 5—Income Taxes under Item 1 in this Quarterly Report, at March 31, 2012, we had a full valuation allowance against our U.S. and Canada net deferred tax assets.  During the second quarter of 2012, we concluded that it was appropriate to reverse the U.S. valuation allowance, but retained a full valuation allowance on our Canadian net deferred tax assets.  We recognized a net deferred tax liability and income tax expense of $25.9 million as of June 30, 2012 and for the six months then ended, respectively.  For the six months ended June 30, 2011, there was no income tax expense or benefit recognized as we had a full valuation allowance on our U.S. and Canadian net deferred tax assets.

 

Net income.  Our net income was $94.8 million for the six months ended June 30, 2012, as compared to $6.8 million for the six months ended June 30, 2011. Our net income for the six months ended June 30, 2012 was positively impacted by our gain on commodity price risk management activities and higher operating income.  However, these increases were negatively impacted by increased DD&A, G&A, interest expense, and income tax expense.

 

Commitments and Contingencies

 

For a discussion of our commitments and contingencies, please refer to Note 11—Commitments and Contingencies under item 1 in this Quarterly Report, which is incorporated herein by reference.

 

Off Balance Sheet Arrangements

 

The Company did not have any off balance sheet arrangements, as such term is defined in Item 303(a)(4)(ii) of Regulation S-K, at June 30, 2012 and December 31, 2011.

 

Critical Accounting Policies and Estimates

 

The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Certain of the Company’s accounting policies are considered critical, as these policies are the most important to the depiction of the Company’s financial statements and require significant, difficult or complex judgments, often employing the use of estimates about the effects of matters that are inherently uncertain. A summary of the Company’s significant accounting policies is included in Note 2 to the Company’s consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2011, as well as in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in such Form 10-K, which summary is qualified by the updates set forth below.  The updated disclosures set forth below have been included solely to clarify our actual treatment with respect to the applicable topics and do not reflect any change in accounting treatment relating thereto.

 

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.

 

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Table of Contents

 

Recently Issued Accounting Pronouncements

 

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

 

Effects of Pricing and Inflation

 

The demand for oil field products and services has increased in the Williston Basin beginning in 2010 and continued throughout 2011 and 2012. Typically, as prices for oil and natural gas increase, so do the associated costs. As oil and natural gas prices decline, we would expect associated costs to decline, however, there may be a lag or the changes may be disproportionate to the lower prices. Material changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, depletion expense, impairment assessments of oil and gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

 

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Commodity Price Risk

 

Our primary market risk is the volatility of oil and natural gas prices. The market prices for oil and natural gas have been highly volatile and are likely to continue to be highly volatile in the future, which will impact our prospective revenues from the sale of products or properties. We manage this commodity price risk exposure through the use of derivative financial instruments entered into with third-party counterparties. Currently, we utilize swaps and “no premium” collars to reduce the effect of price changes on a portion of our future oil production. We do not enter into derivative instruments for trading purposes.

 

We also use swaps to fix the sales price for our anticipated future oil production. Upon settlement, we receive a fixed price for the hedged commodity and pay our counterparty a floating market price, as defined in each instrument. These instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, we pay our counterparty. When the fixed price exceeds the floating price, our counterparty is required to make a payment to us.

 

We use no premium collars to establish floor and ceiling prices on our anticipated future oil production. We neither receive nor pay net premiums when we enter into these arrangements. These contracts are settled monthly. When the settlement price (the market price for oil or natural gas on the settlement date) for a period is above the ceiling price, we pay our counterparty. When the settlement price for a period is below the floor price, our counterparty is required to pay us. All hedges are accounted for using mark-to-market accounting.

 

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 wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc., is currently a party to derivative contracts with three counterparties, and the Company is a guarantor of Kodiak Oil & Gas (USA) Inc. 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. Although the instruments are valued using indices published by established exchanges, the instruments are traded directly with the counterparties. 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 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, these instruments 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.

 

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Table of Contents

 

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

 

Collars

 

Quantity
(Bbl/d)

 

Strike Price
($/Bbl)

 

Jul 1, 2012—Dec 31, 2012

 

400

 

$70.00 - $95.56

 

Jul 1, 2012—Dec 31, 2012

 

230

 

$85.00 - $117.73

 

Jul 1, 2012—Dec 31, 2013

 

500

 

$85.00 - $117.00

 

Jan 1, 2013—Dec 31, 2015

 

300 - 425

 

$85.00 - $102.75

 

 

Swaps

 

Quantity
(Bbl/d)

 

Swap Price
($/Bbl)

 

2012 Total/Average

 

9,010

 

$

98.22

 

2013 Total/Average

 

8,105

 

$

96.45

 

2014 Total/Average

 

2,800

 

$

91.86

 

2015 Total/Average

 

1,625

 

$

87.13

 

 


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

 

We determine the estimated 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. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of whether the 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.  For further details regarding our derivative contracts please refer to Note 6—Commodity Derivative Instruments under Item 1 in this Quarterly Report.

 

Interest Rate Risk

 

At June 30, 2012, we had $800 million 8.125% Senior Notes outstanding due December 1, 2019, all of which has fixed rate interest.

 

In addition, as of June 30, 2012, we had $225.0 million available to us under our credit facility, none of which was drawn at June 30, 2012   The credit facility bears interest at variable rates. Assuming we had the maximum amount outstanding at June 30, 2012 under our credit facility of $225.0 million, a 1.0% increase in interest rates would result in additional annualized interest expense of approximately $2.3 million.

 

For a detailed discussion of the foregoing credit arrangements, including a discussion of the applicable interest rates, please refer to Note 4—Long-Term Debt under Item 1 in this Quarterly Report.

 

ITEM 4.  CONTROLS AND PROCEDURES

 

Management, with the participation of our President and Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of June 30, 2012. On the basis of this review, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our President and Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

 

There have not been any changes in the Company’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated by the SEC under the Exchange Act) during the Company’s most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect the Company’s internal control over financial reporting.

 

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PART II—OTHER INFORMATION

 

ITEM 1.  LEGAL PROCEEDINGS

 

From time to time, the Company is a party to routine litigation and proceedings that are considered part of the ordinary course of its business. The Company is not aware of any material current, pending, or threatened litigation.

 

ITEM 1A.  RISK FACTORS

 

There have been no material changes to the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2011, as filed with the SEC on February 28, 2012.  The risk factors in our Annual Report on Form 10-K for the year ended December 31, 2011, in addition to the other information set forth in this quarterly report, could materially affect our business, financial condition or results of operations. Additional risks and uncertainties not currently known to us or that we deem to be immaterial could also materially adversely affect our business, financial condition or results of operations.

 

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

 

None.

 

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

 

None.

 

ITEM 4.  MINE SAFETY DISCLOSURES

 

These disclosures are not applicable to us.

 

ITEM 5.  OTHER INFORMATION

 

None.

 

ITEM 6.  EXHIBITS

 

Exhibit
Number

 

Description

 

 

 

23.1

 

Consent of Netherland Sewell & Associates, Inc.

 

 

 

31.1

 

Certification of the Principal Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002

 

 

 

31.2

 

Certification of the Principal Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 2002

 

 

 

32.1

 

Certification of the Principal Executive Officer pursuant to 18 U.S.C. Section 1350

 

 

 

32.2

 

Certification of the Principal Financial Officer pursuant to 18 U.S.C. Section 1350

 

 

 

99.1

 

Report of Netherland Sewell & Associates, Inc.

 

 

 

101

 

The following materials are filed herewith: (i) XBRL Instance, (ii) XBRL Taxonomy Extension Schema, (iii) XBRL Taxonomy Extension Calculation, (iv) XBRL Taxonomy Extension Labels, (v) XBRL Taxonomy Extension Presentation, and (vi) XBRL Taxonomy Extension Definition. In accordance with Rule 406T of Regulation S-T, the information in these exhibits is furnished and deemed not filed or a part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Exchange Act of 1934, and otherwise is not subject to liability under these sections and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by the specific reference in such filing.

 

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Table of Contents

 

SIGNATURES

 

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

 

 

KODIAK OIL & GAS CORP.

 

 

 

 

August 2, 2012

/s/ LYNN A. PETERSON

 

Lynn A. Peterson
President and Chief Executive Officer

 

 

 

 

August 2, 2012

/s/ JAMES P. HENDERSON

 

James P. Henderson
Chief Financial Officer
(principal financial and accounting officer)

 

39