XNYS:KOG Kodiak Oil & Gas Corp Quarterly Report 10-Q Filing - 3/31/2012

Effective Date 3/31/2012

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 March 31, 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

 

263,530,643 shares, no par value, of the Registrant’s common stock were issued and outstanding as of May 1, 2012.

 

 

 




Table of Contents

 

PART 1—FINANCIAL INFORMATION

 

ITEM 1.  FINANCIAL STATEMENTS

 

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

(Unaudited)

 

 

 

March 31, 2012

 

December 31, 2011

 

ASSETS

 

 

 

 

 

Current Assets:

 

 

 

 

 

Cash and cash equivalents

 

$

24,905

 

$

81,604

 

Cash held in escrow

 

 

12,194

 

Accounts receivable

 

 

 

 

 

Trade

 

37,348

 

28,835

 

Accrued sales revenues

 

38,183

 

21,974

 

Commodity price risk management asset

 

688

 

 

Inventory, prepaid expenses and other

 

20,012

 

24,294

 

Total Current Assets

 

121,136

 

168,901

 

 

 

 

 

 

 

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

 

 

 

 

 

Proved oil and gas properties

 

1,117,174

 

598,065

 

Unproved oil and gas properties

 

556,642

 

263,462

 

Wells in progress

 

76,280

 

78,505

 

Equipment and facilities

 

16,115

 

11,186

 

Less-accumulated depletion, depreciation, amortization, and accretion

 

(161,594

)

(135,586

)

Net oil and gas properties

 

1,604,617

 

815,632

 

 

 

 

 

 

 

Cash held in escrow

 

 

691,764

 

Commodity price risk management asset

 

426

 

 

Property and equipment, net of accumulated depreciation of $727 at March 31, 2012 and $618 at December 31, 2011

 

1,418

 

1,276

 

Deferred financing costs, net of accumulated amortization of $15,669 at March 31, 2012 and $15,029 at December 31, 2011

 

21,435

 

21,904

 

 

 

 

 

 

 

Total Assets

 

$

1,749,032

 

$

1,699,477

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

138,970

 

$

78,402

 

Accrued interest payable

 

18,775

 

5,808

 

Commodity price risk management liability

 

20,220

 

11,925

 

Total Current Liabilities

 

177,965

 

96,135

 

 

 

 

 

 

 

Noncurrent Liabilities:

 

 

 

 

 

Credit facilities

 

 

100,000

 

Senior notes

 

650,000

 

650,000

 

Commodity price risk management liability

 

21,470

 

10,035

 

Asset retirement obligations

 

4,975

 

3,627

 

Total Noncurrent Liabilities

 

676,445

 

763,662

 

 

 

 

 

 

 

Total Liabilities

 

854,410

 

859,797

 

 

 

 

 

 

 

Stockholders’ Equity:

 

 

 

 

 

Common stock - no par value; unlimited authorized

 

 

 

 

 

Issued and outstanding: 263,530,643 shares as of March 31, 2012 and 257,987,413 shares as of December 31, 2011

 

997,268

 

944,070

 

Accumulated deficit

 

(102,646

)

(104,390

)

Total Stockholders’ Equity

 

894,622

 

839,680

 

 

 

 

 

 

 

Total Liabilities and Stockholders’ Equity

 

$

1,749,032

 

$

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 March 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

Oil sales

 

$

76,814

 

$

13,020

 

Gas sales

 

3,122

 

314

 

Total revenues

 

79,936

 

13,334

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

Oil and gas production

 

17,300

 

2,574

 

Depletion, depreciation, amortization and accretion

 

26,295

 

3,721

 

General and administrative

 

7,898

 

4,718

 

 

 

 

 

 

 

Total operating expenses

 

51,493

 

11,013

 

 

 

 

 

 

 

Operating income

 

28,443

 

2,321

 

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

Loss on commodity price risk management activities

 

(23,340

)

(9,692

)

Interest income (expense), net

 

(4,627

)

33

 

Other income

 

1,268

 

103

 

Total other income (expense)

 

(26,699

)

(9,556

)

 

 

 

 

 

 

Net income (loss)

 

$

1,744

 

$

(7,235

)

 

 

 

 

 

 

Net income (loss) per common share:

 

 

 

 

 

Basic

 

$

0.01

 

$

(0.04

)

Diluted

 

$

0.01

 

$

(0.04

)

 

 

 

 

 

 

Weighted average common shares outstanding:

 

 

 

 

 

Basic

 

262,660,642

 

178,451,574

 

Diluted

 

266,586,016

 

178,451,574

 

 

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)

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Cash flows from operating activities:

 

 

 

 

 

Net income (loss)

 

$

1,744

 

$

(7,235

)

Reconciliation of net income (loss) to net cash provided by operating activities:

 

 

 

 

 

Depletion, depreciation, amortization and accretion

 

26,295

 

3,721

 

Amortization of deferred financing costs

 

640

 

187

 

Unrealized loss on commodity price risk management activities, net

 

18,616

 

9,350

 

Stock-based compensation

 

2,435

 

1,539

 

Changes in current assets and liabilities:

 

 

 

 

 

Accounts receivable-trade

 

(8,513

)

1,474

 

Accounts receivable-accrued sales revenue

 

(16,209

)

12

 

Prepaid expenses and other

 

(924

)

(295

)

Accounts payable and accrued liabilities

 

28,657

 

(1,589

)

Accrued interest payable

 

467

 

(12

)

Cash held in escrow

 

3,343

 

 

Net cash provided by operating activities

 

56,551

 

7,152

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

Oil and gas properties

 

(704,344

)

(22,423

)

Prepaid tubular goods

 

 

(10,084

)

Equipment, facilities and other

 

(10,329

)

(618

)

Cash held in escrow

 

30,000

 

 

Net cash used in investing activities

 

(684,673

)

(33,125

)

 

 

 

 

 

 

Cash flows from financing activities:

 

 

 

 

 

Repayments under credit facilities

 

(100,000

)

 

Proceeds from the issuance of common shares

 

1,108

 

947

 

Cash held in escrow

 

670,615

 

 

Debt and share issuance costs

 

(300

)

(17

)

Net cash provided by financing activities

 

571,423

 

930

 

 

 

 

 

 

 

Decrease in cash and cash equivalents

 

(56,699

)

(25,043

)

 

 

 

 

 

 

Cash and cash equivalents at beginning of the period

 

81,604

 

101,198

 

 

 

 

 

 

 

Cash and cash equivalents at end of the period

 

$

24,905

 

$

76,155

 

 

 

 

 

 

 

Supplemental cash flow information:

 

 

 

 

 

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

 

$

84,452

 

$

11,589

 

 

 

 

 

 

 

Oil & gas property acquired through common stock

 

$

49,798

 

$

 

 

 

 

 

 

 

Cash paid for interest

 

$

3,536

 

$

1,124

 

 

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

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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 entirely 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.

 

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.

 

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.  The Company has not generated taxable income to-date and has incurred a cumulative book loss over the last 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 will be fully realized. The ultimate realization of 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. Future events or new evidence which may lead the

 

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Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings; consistent and sustained pre-tax earnings; sustained or continued improvements in oil and natural gas commodity prices; continued increases in production and proved reserves from the Williston Basin. The Company will continue to evaluate whether a valuation allowance on a separate country basis is needed in future reporting periods.

 

As long as the Company concludes that it will continue to have a need for a full valuation allowance against its net deferred tax assets, the Company likely will not have any income tax expense or benefit, a release of a portion of the valuation allowance for net operating loss carryback claims or for state income taxes. Due to the valuation allowance, no income tax expense or benefit was recorded for the three months ended March 31, 2012 and 2011.

 

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of March 31, 2012, the Company made 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, 2000. 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.

 

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.

 

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.

 

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Note 3—Acquisitions

 

January 2012 Acquisition

 

On January 10, 2012, (“Closing Date”) the Company acquired two separate private, unaffiliated oil and gas company’s (“Sellers”) 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 (the “January 2012 Acquired Properties”) for a combination of cash and stock. The Seller received 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 at the Closing Date. The acquisition provided strategic additions adjacent to the Company’s core project area.  The January 2012 Acquired Properties contributed revenue of $13.8 million to Kodiak for the three months ended March 31, 2012.  Total transaction costs related to the acquisition were approximately $295,000, of which $85,000 and $0 were recorded in the statement of operations within the general and administrative expenses line item for the three months ended March 31, 2012 and 2011, respectively.  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. Management has not had the opportunity to complete its assessment of the fair values of assets acquired and liabilities assumed. The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed and is subject to revision, which may be material, 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

 

317,253

 

Wells in progress

 

25,745

 

Equipment and facilities

 

7,025

 

Total fair value of oil and gas properties acquired

 

647,113

 

 

 

 

 

Working capital

 

(8,095

)

Asset retirement obligation

 

(800

)

 

 

 

 

Fair value of net assets acquired

 

$

638,218

 

 

 

 

 

Working capital acquired was estimated as follows:

 

 

 

Accounts receivable

 

$

8,000

 

Prepaid completion costs

 

465

 

Crude oil inventory

 

540

 

Accrued liabilities

 

(12,400

)

Suspense payable

 

(4,700

)

 

 

 

 

Total working capital

 

$

(8,095

)

 


*                 The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company’s closing stock price on the measurement date of January 10, 2012. (5,055,612 × $9.85)

 

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October 2011 Acquisition

 

On October 28, 2011, (“Closing Date”) the Company acquired a private, unaffiliated oil and gas company’s (“Seller”) 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 “October 2011 Acquired Properties”). The Seller received cash consideration of approximately $248.2 million and the effective date was August 1, 2011, with purchase price adjustments calculated at the Closing Date. The total purchase included approximately $245.5 million related to the acquisition of the properties and approximately $3.3 million related to the assumption of certain working capital items. The acquisition provided strategic additions adjacent to the Company’s core project area. The October 2011 Acquired Properties contributed revenue of $13.8 million to Kodiak for the three months ended March 31, 2012. 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 the October 2011 Acquired Properties were recorded within the three months ended March 31, 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 transactions 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, (“Closing Date”) the Company acquired a private, unaffiliated oil and gas company’s (“Seller”) 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 (the “June 2011 Acquired Properties”) 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 at the Closing Date. The acquisition provided strategic additions to the Company’s core positions in Koala, Smokey and Grizzly Project areas. The June 2011 Acquired Properties contributed revenue of $436,000 to Kodiak for the three months ended March 31, 2012.  Total transaction costs related to the acquisition were approximately $265,000.  Transaction costs are recorded in the statement of operations within the general and administrative expenses line item.  No transaction costs for the June 2011 Acquired Properties were recorded within the three months ended March 31, 2012 and 2011. 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 January 2012 Acquired Properties, October 2011 Acquired Properties and June 2011 Acquired Properties for the three months ended March 31, 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 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 $600,000 and $3.6 million and amortization of financing costs of $0 and $400,000 for the three months ended March 31, 2012 and 2011, respectively. For the three months ended March 31, 2012, there was a pro forma adjustment of $400,000 reducing interest expense. For the three months ended March 31, 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 $14.3 million for the three months ended March 31, 2012 and 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 March 31,

 

 

 

2012

 

2011

 

Operating revenues

 

$

81,736

 

$

21,131

 

Net income (loss)

 

$

2,969

 

$

(5,428

)

Net income (loss) per common share

 

 

 

 

 

Basic

 

$

0.01

 

$

(0.03

)

Diluted

 

$

0.01

 

$

(0.03

)

 

Note 4—Long-Term Debt

 

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

 

 

 

March 31, 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

 

650,000

 

650,000

 

Total Long-Term Debt

 

$

650,000

 

$

750,000

 

Less: Current Portion of Long Term Debt

 

 

 

Total Long-Term Debt, Net of Current Portion

 

$

650,000

 

$

750,000

 

 

9



Table of Contents

 

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 current borrowing base of $225.0 million. 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. The credit facility matures on October 28, 2016.

 

Interest on the revolving loans 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 March 31, 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 March 31, 2012, the Company was in compliance with all financial covenants under the credit facility.

 

As of March 31, 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 March 31, 2012, the Company borrowed $30.0 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.

 

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

 

On November 23, 2011, the Company issued at par $650.0 million of 8.125% Senior Notes due December 1, 2019 (the “Senior Notes”). The interest on the Senior Notes is payable on June and December 1 of each year, beginning June 1, 2012. The proceeds received from the offer and sale of the Senior Notes were deposited into an escrow account, along with cash of the Company, in an amount equal to 101% of the offering price of the Senior Notes and the interest payable on the Senior Notes to March 22, 2012.  At December 31, 2011, there was $674.0 million in cash held in escrow related to the Senior Notes. As discussed in Note 3—Acquisitions, in January 2012, the Company completed the acquisition of the January 2012

 

10



Table of Contents

 

Acquired Properties and all funds were released from escrow. 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 December 31, 2011, 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 March 31, 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.

 

Deferred Financing Costs

 

As of March 31, 2012, the Company had deferred financing costs of $21.4 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. For the three months ended March 31, 2012 and 2011, the Company recorded amortization expense of the deferred financing costs of $640,000 and $187,000, respectively.

 

Interest Incurred On Long-Term Debt

 

For the three months ended March 31, 2012 and 2011, the Company incurred interest expense on long-term debt of $13.5 million and $1.1 million, respectively. Of the total interest incurred, the Company capitalized interest costs of $12.5 million and $1.1 million for the three months ended March 31, 2012 and 2011, respectively.

 

11



Table of Contents

 

Note 5— 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.

 

12



Table of Contents

 

The Company’s commodity derivative contracts as of March 31, 2012 are summarized below:

 

Contract Type

 

Counterparty

 

Basis(1)

 

Quantity(B
bl/d)

 

Strike Price
($/Bbl)

 

Term

 

Collar

 

Wells Fargo Bank, N.A.

 

NYMEX

 

400

 

$70.00/$95.56

 

Apr 1, 2012—Dec 31, 2012

 

Collar

 

Wells Fargo Bank, N.A.

 

NYMEX

 

230

 

$85.00/$117.73

 

Apr 1, 2012—Dec 31, 2012

 

Collar

 

Shell Trading (U.S.)

 

NYMEX

 

500

 

$85.00 - $117.00

 

Apr 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(B
bl/d)

 

Strike Price
($/Bbl)

 

Term

 

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

100

 

$84.00

 

Apr 1, 2012—Dec 31, 2012

 

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

136

 

$88.30

 

Apr 1, 2012—Dec 31, 2012

 

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

24

 

$90.28

 

Apr 1, 2012—Dec 31, 2012

 

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

500

 

$85.00

 

Apr 1, 2012—Dec 31, 2012

 

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

1,000

 

$85.07

 

Apr 1, 2012—Dec 31, 2012

 

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

1,000

 

$102.05

 

Apr 1, 2012—Dec 31, 2012

 

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

500

 

$107.20

 

Apr 1, 2012—Dec 31, 2012

 

Swap

 

Shell Trading (U.S.)

 

NYMEX

 

250

 

$85.01

 

Apr 1, 2012—Dec 31, 2012

 

Swap

 

Shell Trading (U.S.)

 

NYMEX

 

2,000

 

$96.88

 

Apr 1, 2012—Dec 31, 2012

 

Swap

 

Credit Suisse International

 

NYMEX

 

500

 

$106.85

 

Apr 1, 2012—Dec 31, 2012

 

Swap

 

Credit Suisse International

 

NYMEX

 

500

 

$107.25

 

Apr 1, 2012—Dec 31, 2012

 

2012 Total/Average

 

 

 

 

 

6,510

 

$96.45

 

 

 

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

 

Shell Trading (U.S.)

 

NYMEX

 

250

 

$85.01

 

Jan 1, 2013—Dec 31, 2013

 

2013 Total/Average

 

 

 

 

 

3,105

 

$92.76

 

 

 

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—Sept 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

 

 

 

 

Subsequent to March 31, 2012, the Company entered into additional commodity derivative contracts as summarized below:

 

Contract Type

 

Counterparty

 

Basis(1)

 

Quantity(B
bl/d)

 

Swap Price
($/Bbl)

 

Term

 

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

1,000

 

$102.88

 

May 1, 2012 - Dec 31, 2012

 

Swap

 

Shell Trading (U.S.)

 

NYMEX

 

500

 

$102.85

 

May 1, 2012 - Dec 31, 2012

 

Swap

 

Credit Suisse International

 

NYMEX

 

1,000

 

$102.83

 

May 1, 2012 - Dec 31, 2012

 

Swap

 

Wells Fargo Bank, N.A.

 

NYMEX

 

1,000

 

$101.55

 

Jan 1, 2013 - Dec 31, 2013

 

Swap

 

Shell Trading (U.S.)

 

NYMEX

 

500

 

$101.32

 

Jan 1, 2013 - Dec 31, 2013

 

Swap

 

Credit Suisse International

 

NYMEX

 

1,000

 

$101.60

 

Jan 1, 2013 - Dec 31, 2013

 

 


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

 

13



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 March 31, 2012

 

As of December 31, 2011

 

Crude oil derivative contract

 

Current assets

 

$

688

 

$

 

Crude oil derivative contract

 

Noncurrent assets

 

$

426

 

$

 

Crude oil derivative contract

 

Current liabilities

 

$

20,220

 

$

11,925

 

Crude oil derivative contract

 

Noncurrent liabilities

 

$

21,470

 

$

10,035

 

 

The amount of loss recognized in income related to our derivative financial instruments was as follows (in thousands):

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

Unrealized loss on oil contracts

 

$

(18,616

)

$

(9,350

)

Realized loss on oil contracts

 

(4,724

)

(342

)

Loss on commodity price risk management activities

 

$

(23,340

)

$

(9,692

)

 

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 6—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 cost is depreciated over the estimated life of the producing property.

 

 

 

For the Three Months
Ended March 31, 2012

 

For the Year Ended
December 31, 2011

 

 

 

($ in thousands)

 

Balance beginning of period

 

$

3,627

 

$

1,968

 

Liabilities incurred or acquired

 

1,220

 

1,655

 

Liabilities settled

 

(42

)

(610

)

Revisions in estimated cash flows

 

 

418

 

Accretion expense

 

170

 

196

 

Balance end of period

 

$

4,975

 

$

3,627

 

 

14



Table of Contents

 

Note 7—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:

 

·                  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 6 - 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 at 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 March 31, 2012 by level within the fair value hierarchy (in thousands):

 

 

 

Fair Value Measurements at March 31, 2012 Using

 

 

 

Level 1

 

Level 2

 

Level 3

 

Total

 

 

 

 

 

 

 

 

 

 

 

Financial Assets:

 

 

 

 

 

 

 

 

 

Commodity price risk management liability

 

$

 

$

1,114

 

$

 

$

1,114

 

 

 

 

 

 

 

 

 

 

 

Financial Liabilities:

 

 

 

 

 

 

 

 

 

Commodity price risk management liability

 

$

 

$

(41,690

)

$

 

$

(41,690

)

 

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 March 31, 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.

 

15



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 and accounts receivable, 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 March 31, 2012

 

At December 31, 2011

 

 

 

Carrying
Amount

 

Fair Value

 

Carrying
Amount

 

Fair Value

 

 

 

 

 

 

 

 

 

 

 

Second Lien Credit Agreement

 

$

 

$

 

$

100,000

 

$

103,000

 

8.125% Senior Notes

 

$

650,000

 

$

687,375

 

$

650,000

 

$

656,500

 

 

Note 8—Share-Based Payments

 

The Company has granted options to directors, officers, and employees of the Company under the 2007 Stock Incentive Plan (the “Plan”), amended on June 3, 2010 and further amended on June 15, 2011. 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, 2011, the maximum number of shares issuable under the Plan, including those previously issued thereunder, was approximately 24.9 million shares. The June 15, 2011 amendment referenced above limited the number of shares of common stock available for granting incentive stock options under the Plan to 24.5 million shares, eliminated the limitation on the number of shares available for granting restricted stock and clarified the duration of the restriction limiting the grant of performance-based awards to individual Plan participants.

 

Stock Options

 

Total compensation expense related to the stock options of $1.4 million and $1.3 million was recognized for the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012, there was $8.4 million of total unrecognized compensation cost related to stock options, which is expected to be amortized over a weighted-average period of 1.90 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 period presented:

 

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For the Three Months
Ended March 31, 2012

 

For the Year Ended
December 31, 2011

 

 

 

 

 

 

 

Risk free rates

 

0.99-1.48%

 

1.06 - 2.57%

 

Dividend yield

 

0%

 

0%

 

Expected volatility

 

89.08 - 90.25%

 

90.43 - 94.97%

 

Weighted average expected stock option life

 

5.63 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

 

$

7.11

 

$

5.10

 

Total options granted

 

445,500

 

1,712,500

 

 

 

 

 

 

 

Total weighted average fair value of options granted

 

$

3,167,505

 

$

8,733,750

 

 

A summary of the stock options outstanding as of January 1, 2012 and March 31, 2012 is as follows:

 

 

 

 

 

Weighted

 

 

 

 

 

Average

 

 

 

Number of

 

Exercise

 

 

 

Options

 

Price

 

Balance outstanding at January 1, 2012

 

6,591,158

 

$

3.77

 

 

 

 

 

 

 

Granted

 

445,500

 

9.83

 

Canceled

 

(195,500

)

5.49

 

Exercised

 

(457,618

)

2.42

 

 

 

 

 

 

 

Balance outstanding at March 31, 2012

 

6,383,540

 

$

4.24

 

 

 

 

 

 

 

Options exercisable at March 31, 2012

 

4,007,040

 

$

2.92

 

 

At March 31, 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

 

309,000

 

5.7

 

$

0.36

 

309,000

 

5.7

 

$

0.36

 

$1.01-$2.00

 

895,917

 

2.1

 

$

1.18

 

895,917

 

2.1

 

$

1.18

 

$2.01-$3.00

 

926,870

 

7.3

 

$

2.36

 

625,870

 

6.9

 

$

2.32

 

$3.01-$4.00

 

1,798,753

 

4.4

 

$

3.47

 

1,622,753

 

4.1

 

$

3.47

 

$4.01-$5.00

 

155,000

 

9.0

 

$

4.47

 

25,000

 

8.6

 

$

4.26

 

$5.01-$6.00

 

293,000

 

9.1

 

$

5.50

 

25,000

 

8.7

 

$

5.44

 

$6.01-$7.00

 

1,140,500

 

7.8

 

$

6.41

 

488,000

 

6.2

 

$

6.38

 

$7.01-$8.00

 

115,000

 

9.2

 

$

7.20

 

16,000

 

8.9

 

$

7.20

 

$8.01-$9.00

 

259,000

 

9.7

 

$

8.72

 

 

 

$

 

$9.01-$10.53

 

490,500

 

9.8

 

$

9.75

 

 

 

$

 

 

 

6,383,540

 

6.2

 

$

4.26

 

4,007,540

 

4.5

 

$

2.92

 

 

The aggregate intrinsic value of both outstanding and vested options as of March 31, 2012 was $36.5 million based on the Company’s March 31, 2012 closing common stock price of $9.96 per share. The total grant date fair value of the shares vested during 2012 was $1.6 million.

 

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Restricted Stock Units and Restricted Stock

 

Total compensation expense related to restricted stock units (“RSUs”) and restricted stock of $1.0 million and $237,000 was recognized for the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012, there was $6.4 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 2.21 years.

 

In the fourth quarter 2011, the Company awarded 775,611 performance based RSUs to officers pursuant to the Company’s 2007 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.

 

In the first quarter of 2012, the Company awarded grants of 30,000 shares of restricted stock to its Board of Directors pursuant to the Company’s 2007 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 quarter 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 March 31, 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 three months ended March 31, 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 at January 1, 2012

 

1,008,111

 

$

8.48

 

 

 

 

 

 

 

Granted

 

30,000

 

9.87

 

Forfeited

 

 

 

Vested

 

(22,500

)

7.39

 

Non-vested restricted stock at March 31, 2012

 

1,015,611

 

$

8.55

 

 

Note 9—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 8—Share-Based Payments under the heading Restricted Stock Units and Restricted Stock for additional discussion.

 

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The table below sets forth the computations of basic and diluted net income (loss) per share for the three months ended March 31, 2012 and 2011 (in thousands, except per share data):

 

 

 

For the Three Months Ended March 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Basic net income (loss)

 

$

1,744

 

$

(7,235

)

Income allocable to participating securities

 

(1

)

 

Diluted net income (loss)

 

$

1,743

 

$

(7,235

)

 

 

 

 

 

 

Basic weighted average common shares outstanding

 

262,660,642

 

178,451,574

 

Effect of dilutive securities

 

 

 

 

 

Options to purchase common shares

 

5,978,040

 

 

Assumed treasury shares purchased

 

(2,372,171

)

 

Unvested restricted stock units

 

319,505

 

 

Diluted weighted average common shares outstanding

 

266,586,016

 

178,451,574

 

 

 

 

 

 

 

Basic net income (loss) per share

 

$

0.01

 

$

(0.04

)

Diluted net income (loss) per share

 

$

0.01

 

$

(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 March 31,

 

 

 

2012

 

2011

 

Anti-dilutive shares

 

405,500

 

652,000

 

 

Note 10—Commitments and Contingencies

 

Lease Obligations

 

The Company leases office space in Denver, Colorado and Dickinson, North Dakota under separate operating lease agreements. The Denver, Colorado lease expires on April 30, 2016. The Dickinson, North Dakota lease expires December 31, 2013. Total rental commitments under non-cancelable leases for office space were $2.8 million at March 31, 2012.  The future minimum lease payments under these non-cancelable leases are as follows: $440,000 in 2012, $600,000 in 2013, $600,000 in 2014, $625,000 in 2015, and $540,000 in 2016.

 

Drilling Rigs

 

As of March 31, 2012 the Company was subject to commitments on six drilling rig contracts. One of the contracts expires in 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 $60.9 million as of March 31, 2012 as required under the varying terms of such contracts.

 

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Pressure Pumping Services

 

As of March 31, 2012, the Company was subject to a commitment with a pressure-pumping service company providing 24-hour per day frac 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 March 31, 2012 as required under the terms of the contract.

 

Guarantees

 

In November 2011, the Company issued $650.0 million of Senior Notes due in 2019 which 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. The guarantee is full and unconditional, and the parent company has no other subsidiaries. In addition, there are no restrictions 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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Table of Contents

 

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, increases 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 or natural gas production or oil or natural gas prices, and the impact of general economic conditions on the demand for oil and natural gas 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 or natural gas 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.

 

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 natural gas in the United States. We have developed an oil and natural gas 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 oil and natural gas reserves and operations are primarily concentrated in the Williston Basin of North Dakota and to a lesser extent the Greater Green River Basin of Wyoming.  As of March 31, 2012, we owned an interest in approximately 238,000 gross (157,000 net) acres in the Williston Basin where our primary target is the middle Bakken and Three Forks formations.

 

Since late 2010 through the first quarter of 2012, 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.

 

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As of the date of this filing, we operate six drilling rigs on our acreage, and we have a seventh rig under contract for delivery in the second quarter of 2012.  The Company also has a full-time, 24-hour-per-day completion crew that commenced work on our behalf at the beginning of the year.  We intend to utilize a second completion crew in order to accelerate completion activity.  In addition, our partner in an area of mutual interest is currently operating two rigs.  We have an approximate 50% ownership in this area of mutual interest.  As of April 2012, we have an interest in 160 gross (65.9 net) producing wells in the Williston Basin.

 

Recent Developments

 

Operational Update

 

During the first quarter 2012, we focused on integrating our October 2011 and January 2012 property acquisitions into our operations.  Due to a shortage of workover rigs in late 2011 and early 2012, we encountered delays while installing artificial lift on some of the wells.  The result was that these wells were shut in during those time periods, but were returned to production in mid-February.  In addition, during the first quarter of 2012, additional completion procedures were required on several of the wellbores acquired in our October 2011 and January 2012 property acquisitions to bring the wells on to production.

 

During the first quarter of 2012, we continued our repair and remediation work on wells that encountered mechanical issues during completion procedures during the end of 2011 and in early 2012. We successfully repaired two wells, one of which has been completed in the sleeve stages and flowed back at a rate of 765 BOE/d from five stages.  The remaining plug and perforation stages will be completed at a later date.  The second well is currently scheduled for completion in the second quarter of 2012.  Ultimately, we expect all of the wells to be remediated and undergo completion operations.  We now anticipate the wells coming on-line during the last three quarters of 2012.  We have addressed these mechanical issues predominantly through the use of cemented liners in new wells being drilled, which we believe reduces our risk of mechanical failures.

 

In the first quarter of 2012, we focused on delineating our acreage in the more outlying areas by drilling the Grizzly and Charging Eagle wells.  We are very pleased with the four gross (2.3 net) Charging Eagle wells completed in the very southeastern portion of Dunn County, one of which was a Three Forks test.  We also completed three gross (2.5 net) wells in our Grizzly project area in southwest McKenzie County that is characterized by lower reservoir pressures which do not yield the robust initial production rates common in other parts of the Basin. Further details of these wells are shown in the summary drilling and completion schedule below.  For the remainder of the year, we expect all of our operated wells to be drilled and completed through the heart of our core leasehold in southern Williams, McKenzie and Dunn counties, where we carry a high working interest in the wells.

 

Overall, during the first quarter of 2012, we drilled 14 gross (12.1 net) operated wells and completed 12 gross (8.0 net) operated wells.  As of March 31, 2012 Kodiak had 14 gross (12.6 net) operated wells drilled and waiting to be completed.  Completion operations have recently finished on two gross (1.9 net) operated wells in April that are now flowing back.  The Company expects an additional 12 gross (10.7 net) operated wells to be completed during the remainder of the second quarter of 2012.

 

Furthermore, the Company participated in the drilling of 21 gross (3.9 net) non-operated wells and the completion of nine gross (2.1 net) non-operated well during the first quarter of 2012.  As of March 31, 2012 the Company has an interest in 16 gross (3.3 net) non-operated wells that are waiting on completion.

 

Overall, we anticipate that our drilling and well completion efforts will continue on pace the remainder of 2012 with a total of 73 gross (51.0 net) operated wells projected to be completed by year-end.

 

Generally, in the Williston Basin, oil, gas and water infrastructure continues to improve.  The majority of our wells in Dunn County are connected to pipeline infrastructure to transport oil, gas and water.  The ability to sell and process gas from these wells continues to be constrained due to process plant capacity restrictions.  Some of these restrictions are being eliminated as additional capacity has been brought on-line during the first quarter and will continue to expand into 2012.  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 both oil and gas by year-end.  To date, we have drilled the first of three expected water disposal wells on our acreage.  With the addition of these wells and future water gathering systems, we anticipate that our operating costs, on a per unit basis, will improve.

 

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

 

Kodiak Oil & Gas Corp.

Q1 2012 Bakken and Three Forks Completion Activities

 

 

 

 

 

 

 

 

 

Production Volumes (BOE/d)

 

 

 

WI / NRI

 

 

 

Length of

 

IP 24 Hour

 

30 Day

 

60 Day

 

Well Name

 

(%)

 

Formation

 

Lateral

 

Test

 

Cum

 

Cum

 

Dunn County, ND

 

Skunk Creek 2-8-17-14H3

 

44 / 38

 

Three Forks

 

9,354’

 

2,680

 

1,277

 

1,048

 

Skunk Creek 9-2-3-5H

 

99 / 81

 

Bakken

 

9,240’

 

2,174

 

912

 

 

Charging Eagle 15-14-11-4H

 

60 / 49

 

Bakken

 

9,209’

 

2,429

 

921

 

 

Charging Eagle 15-14-24-16H

 

60 / 49

 

Bakken

 

8,695’

 

1,716

 

646

 

 

Williams and McKenzie Counties, ND

 

Grizzly 149-104-15-12-1-2H

 

78 / 64

 

Bakken

 

8,632’

 

1,026

 

 

 

Grizzly 3-25-13-3H

 

86 / 71

 

Bakken

 

10,075’

 

508

 

 

 

Grizzly 3-25-36-15H

 

90 / 74

 

Bakken

 

9,407’

 

689

 

401

 

 

Pankowski 4-6H

 

61 / 49

 

Three Forks

 

8,860’

 

1,588

 

 

 

Long 112-1H

 

73 / 56

 

Bakken

 

9,583’

 

1,978

 

1,017

 

908

 

Lind 211-1H

 

70 / 54

 

Bakken

 

9,563’

 

1,419

 

704

 

560

 

Mildred 94-1H

 

45 / 35

 

Bakken

 

10,041’

 

1,396

 

495

 

427

 

State 1621-1H

 

36 / 28

 

Bakken

 

8,926’

 

1,658

 

525

 

446

 

Non-Operated: Dunn County, ND

 

FBIR Darcie 34X-10 (1)

 

44 / 36

 

Bakken

 

9,494’

 

1,561

 

N/A

 

N/A

 

FBIR IronWoman 21X-10 (1)

 

50 / 41

 

Bakken

 

9,467’

 

2,355

 

N/A

 

N/A

 

FBIR WalterPacksWolf 31X-12

 

50 / 41

 

Bakken

 

9,217’

 

1,290

 

N/A

 

N/A

 

FBIR YellowWolf 21X-10

 

50 / 41

 

Bakken

 

9,720’

 

1,445

 

N/A

 

N/A

 

FBIR GuyBlackHawk 24X-27

 

50 / 41

 

Bakken

 

9,221’

 

Well on Confidental Status

 

 


(1) Wells completed in Q4 2011.

 

Closing on Acquisition of Williston Basin Properties

 

On January 10, 2012, we closed an acquisition of approximately 50,000 net oil and gas leasehold acres and producing properties located principally in Williams and McKenzie counties of North Dakota, and various other related rights, permits, contracts, equipment and other assets, including the assignment and assumption of a drilling rig contract (the “January 2012 Acquisition”). The effective date for this acquisition was September 1, 2011.

 

We closed this acquisition for aggregate consideration of approximately $638.2 million. This consideration was comprised of (i) 5,055,612 shares of the Company’s common stock and (ii) cash consideration in an amount equal to approximately $588.4 million. The purchase price included normal closing adjustments to reflect the effective date of the acquisition, which includes reimbursement to the seller in this transaction for operational expenditures during the timeframe between the effective date of the acquisition and the closing date. We funded the cash balance due at closing through the release from escrow of the proceeds from our November 2011 high yield debt offering.

 

Regulatory Matters

 

On April 17, 2012, the Environmental Protection Agency (“EPA”) 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 (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The EPA rules include NSPS 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,” technologies that are already widely deployed at wells.  The finalized regulations 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 the Company’s operations, including the installation of new equipment to control emissions. The Company is currently evaluating the effect these rules will have on its business.

 

Capital Resources and Liquidity

 

2012 Capital Expenditures Budget

 

Our 2012 capital expenditure budget of $585.0 million (exclusive of $647.1 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 three months of 2012, we invested capital expenditures of approximately $170.0 million related to drilling and completion operations, and related infrastructure and leasehold acquisition (exclusive of our January 2012 Acquisition).  Our 2012 capital expenditures budget is comprised of the following:

 

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·                  $575.0 million for the drilling and completion of 73 gross and (51.0 net wells) wells and related infrastructure. In the three month period ended March 31, 2012, we spent approximately $163.2 million on these activities (inclusive of capitalization of $12.5 million of interest). 

 

·                  $10.0 million for leasehold expenditures.  In the three month period ended March 31, 2012, we have purchased 1,680 gross (1,005 net) acres incurring approximately $6.8 million on leasehold expenditures.

 

Senior Notes

 

In November 2011, we issued at par $650.0 million of 8.125% Senior Notes due December 1, 2019, the proceeds of which were deposited into escrow. Upon closing the January 2012 Acquisition, the escrow related to the Senior Notes was released.  The escrow proceeds were primarily used to finance the January 2012 Acquisition and repay all borrowings under the second lien credit agreement. The interest on our Senior Notes is payable on June and December 1 of each year, beginning June 1, 2012. 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 use 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 negative $56.9 million at March 31, 2012 and positive $81.8 million at March 31, 2011. We expect to maintain low cash and cash equivalent balances going forward because we use available funds to reduce our 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) cannot be reported as working capital, we may have low or negative working capital.

 

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 this capital program and meeting our debt service requirements through our existing cash on hand, the increase in our operating cash flows, and additional credit that may be available through our borrowing base facility. We plan to finance the remaining $415.0 million of our $585.0 million 2012 capital expenditure budget utilizing the following sources of capital:

 

Cash flow from operations.  As discussed in more detail below, our net cash provided by operating activities has increased significantly for the three months ended March 31, 2012 as compared to the same period in 2011. This increase is directly related to our successful drilling and completion operations as we have developed our Bakken properties and the addition of producing properties through our acquisition activity. In addition to the increase in the number of wells on production, the per-well production has increased as we have enhanced our completion techniques with advanced fracture stimulations. Throughout 2012, we expect our cash flow from operations to continue to significantly increase commensurate with our increase in estimated production. If we are able to drill and complete our wells as anticipated and they produce at

 

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rates similar to those generated by our existing wells, we would expect our production rates and operating cash flows to grow significantly as we move through 2012. We estimate that our 2012 average daily sales volumes will be approximately 17,000 to 21,000 BOE per day as compared to approximately 4,000 BOE per day in 2011.

 

Credit Facility.  In November 2011, we amended our credit facility pursuant to which we increased our borrowing base to $225.0 million with a maximum credit amount of $750.0 million and a maturity date of November 14, 2016. This facility, as of March 31, 2012, had availability of $225.0 million.  Subsequent to March 31, 2012, we borrowed $30.0 million under this credit facility resulting in availability of $195.0 million as of the date of this filing. Redetermination of the borrowing base occurs semi-annually, on April 1 and October 1.  The borrowing base was reaffirmed as of April 1, 2012, and the Company expects to elect a borrowing base redetermination in order to increase the borrowing base during the second quarter of 2012.  The Company may elect a redetermination of the borrowing base one time during any six month period. The ability to maintain 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 the credit facility please refer to Note 4—Long-Term Debt under Item 1 in this Quarterly Report.

 

If any of these sources were to be unavailable or insufficient to fund our 2012 drilling program, debt service requirements, other contractual obligations and our general and administrative expenses, we would need to secure other sources of funding, such as through the sales of our securities.  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, will be described in detail in a prospectus supplement at the time of any such offering.

 

We expect that our cash flows from operations, our cash on hand and increases in our borrowing base, if necessary and available, will be sufficient to meet our remaining 2012 capital expenditures budget and to satisfy our 2012 obligations under our Senior Notes and other 2012 contractual commitments (please refer to Note 10 - Commitments and Contingencies under Item 1 in this Quarterly Report). If our existing and potential sources of liquidity were not to be 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 the changing commodity price or oil field service environment.  Additionally, we believe the majority of our leasehold can be held by production even with a reduced number of drilling rigs, because much of our leasehold is either currently held by production or will be held by production in the near term. We may incur termination fees depending on the timing and contractual requirements of our drilling rig and completions services contracts. If necessary, we may conduct an offering of our securities.  There can be no assurance that any such transactions can be completed or that such transactions would satisfy our operating capital requirements and other commitments. If we were not successful in obtaining sufficient funding, we would be unable to implement our original exploration and drilling program, and we may be unable to service our debt obligations or satisfy our contractual obligations.

 

Cash Flow Analysis

 

Following is a summary of our change in cash and cash equivalents from March 31, 2011 to March 31, 2012:

 

 

 

($ in thousands)

 

 

 

Three Months Ended March 31,

 

 

 

2012

 

2011

 

Period to period
change

 

Net cash provided by operating activities

 

$

56,551

 

$

7,152

 

$

49,399

 

Net cash used in investing activities

 

(684,673

)

(33,125

)

(651,548

)

Net cash provided by financing activities

 

571,423

 

930

 

570,493

 

Decrease in cash and cash equivalents

 

$

(56,699

)

$

(25,043

)

(31,656

)

 

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). 

 

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For the first three months of 2012 as compared to the same period in 2011, our net cash provided by operating activities increased by $49.4 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 and, to a lesser extent, due to an increase in our accounts payable balance from year-end 2011.

 

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 three months of 2012 as compared to the same period in 2011, our net cash used in investing activities increased by $651.5 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 quarter of 2012 as compared to the same period in 2011.

 

Net cash provided by financing activities.  For the first three months of 2012 as compared to the same period in 2011, our net cash provided by financing activities increased by $570.5 million.  This was a result of our receipt from escrow of $670.6 million, of which $588.4 million was used for closing our January 2012 Acquisition, and $100.0 million was used to repay our entire outstanding balance on our second lien credit agreement.

 

Our Properties

 

Williston Basin (157,000 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. The Williston Basin also produces from many other formations including, but not limited to, the Mission Canyon, Nisku and Red River.

 

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 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 early 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 tight 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. In 2012, we plan to drill all wells from two-well to four-well pads.

 

·                  We expect to drill future wells with the density of approximately 1,300 feet or less of horizontal separation. We have completed five sets of middle Bakken wells 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.

 

·                  Completion techniques have been and will continue to be evaluated with the expectation of further enhancing our completion methods as more data becomes available. Early results from our completion of seven gross operated wells in the Three Forks Formation are similar to the results of our middle Bakken wells and indicative of the

 

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potential of the formation. Results have shown very 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 are drilling water disposal wells on several of our producing areas outside of Dunn County and plan to construct water gathering systems where appropriate.

 

Our Leasehold

 

As of March 31, 2012, we had several hundred lease agreements representing approximately 272,400 gross and 168,400 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

 

25,821

 

5,889

 

1,700

 

953

 

27,521

 

6,842

 

Colorado

 

7,339

 

4,960

 

0

 

0

 

7,339

 

4,960

 

Williston Basin

 

 

 

 

 

 

 

 

 

 

 

 

 

Montana

 

2,359

 

1,240

 

3,240

 

2,446

 

5,599

 

3,686

 

North Dakota

 

132,650

 

87,462

 

99,275

 

65,450

 

231,925

 

152,912

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Acreage Totals

 

168,169

 

99,551

 

104,215

 

68,849

 

272,384

 

168,400

 

 


(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.

 

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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

 

24,543

 

13,953

 

December 31, 2013

 

36,855

 

19,891

 

December 31, 2014

 

13,972

 

14,966

 

December 31, 2015

 

12,044

 

5,355

 

Total

 

87,414

 

54,165

 

 

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 March 31,

 

 

 

2012

 

2011

 

 

 

 

 

 

 

Sales Volume (Bakken):

 

 

 

 

 

Oil (Bbls)

 

874,156

 

149,749

 

Gas (Mcf)

 

493,592

 

21,630

 

 

 

 

 

 

 

Sales Volume (Other):

 

 

 

 

 

Oil (Bbls)

 

4,420

 

7,646