Attached files
| file | filename |
|---|---|
| EXCEL - IDEA: XBRL DOCUMENT - Whiting Canadian Holding Co ULC | Financial_Report.xls |
| EX-31.1 - EXHIBIT 31.1 - Whiting Canadian Holding Co ULC | kogex3110930201410q.htm |
| EX-32.2 - EXHIBIT 32.2 - Whiting Canadian Holding Co ULC | kogex3220930201410q.htm |
| EX-32.1 - EXHIBIT 32.1 - Whiting Canadian Holding Co ULC | kogex3210930201410q.htm |
| EX-31.2 - EXHIBIT 31.2 - Whiting Canadian Holding Co ULC | kogex3120930201410q.htm |
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 September 30, 2014
Commission file number: 001-32920
(Exact name of registrant as specified in its charter)
Yukon Territory (State or other jurisdiction of incorporation or organization) | N/A (I.R.S. Employer Identification No.) |
1625 Broadway, Suite 250 | |
Denver, Colorado 80202 | (303) 592-8075 |
(Address of principal executive offices) | (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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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 the definitions of “large accelerated filer", "accelerated filer", and "smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer x | Accelerated filer o | Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
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
267,864,101 shares. no par value, of the Registrant’s common stock were issued and outstanding as of November 5, 2014
KODIAK OIL & GAS CORP.
INDEX
2
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
KODIAK OIL & GAS CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
(Unaudited)
September 30, 2014 | December 31, 2013 | |||||||
ASSETS | ||||||||
Current Assets: | ||||||||
Cash and cash equivalents | $ | 29,546 | $ | 90 | ||||
Accounts receivable | ||||||||
Trade | 93,514 | 108,883 | ||||||
Accrued sales revenues | 137,434 | 121,843 | ||||||
Commodity price risk management asset | 23,676 | — | ||||||
Inventory and prepaid expenses | 16,467 | 11,367 | ||||||
Deferred tax asset, net | — | 14,300 | ||||||
Total Current Assets | 300,637 | 256,483 | ||||||
Oil and gas properties (full cost method), at cost: | ||||||||
Proved oil and gas properties | 4,268,960 | 3,556,667 | ||||||
Unproved oil and gas properties | 528,248 | 641,644 | ||||||
Equipment and facilities | 27,805 | 27,712 | ||||||
Less-accumulated depletion, depreciation, amortization, and accretion | (895,101 | ) | (605,700 | ) | ||||
Net oil and gas properties | 3,929,912 | 3,620,323 | ||||||
Commodity price risk management asset | 2,907 | 1,290 | ||||||
Property and equipment, net of accumulated depreciation of $2,999 at September 30, 2014 and $1,980 at December 31, 2013 | 3,947 | 3,928 | ||||||
Deferred financing costs, net of amortization of $27,701 at September 30, 2014 and $22,963 at December 31, 2013 | 37,008 | 41,746 | ||||||
Total Assets | $ | 4,274,411 | $ | 3,923,770 | ||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current Liabilities: | ||||||||
Accounts payable and accrued liabilities | $ | 237,555 | $ | 272,858 | ||||
Accrued interest payable | 30,070 | 24,425 | ||||||
Commodity price risk management liability | — | 20,334 | ||||||
Deferred tax liability, net | 327 | — | ||||||
Total Current Liabilities | 267,952 | 317,617 | ||||||
Noncurrent Liabilities: | ||||||||
Credit facility | 870,000 | 708,000 | ||||||
Senior notes, net of accumulated amortization of bond premium of $1,541 at September 30, 2014 and $1,024 at December 31, 2013 | 1,554,459 | 1,554,976 | ||||||
Deferred tax liability, net | 205,373 | 133,700 | ||||||
Asset retirement obligations | 20,557 | 16,405 | ||||||
Total Noncurrent Liabilities | 2,650,389 | 2,413,081 | ||||||
Total Liabilities | 2,918,341 | 2,730,698 | ||||||
Stockholders’ Equity: | ||||||||
Common stock—no par value; unlimited authorized | ||||||||
Issued and outstanding: 267,864,101 shares as of September 30, 2014 and 266,249,765 shares as of December 31, 2013 | 1,044,982 | 1,024,462 | ||||||
Retained earnings | 311,088 | 168,610 | ||||||
Total Stockholders’ Equity | 1,356,070 | 1,193,072 | ||||||
Total Liabilities and Stockholders’ Equity | $ | 4,274,411 | $ | 3,923,770 | ||||
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
3
KODIAK OIL & GAS CORP.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share data)
(Unaudited)
For the Three Months Ended September 30, | For the Nine Months Ended September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Revenues: | ||||||||||||||||
Oil sales | $ | 272,361 | $ | 286,832 | $ | 787,507 | $ | 606,044 | ||||||||
Gas sales | 19,789 | 12,760 | 61,701 | 32,076 | ||||||||||||
Total revenues | 292,150 | 299,592 | 849,208 | 638,120 | ||||||||||||
Operating expenses: | ||||||||||||||||
Oil and gas production | 79,197 | 59,132 | 208,391 | 132,654 | ||||||||||||
Depletion, depreciation, amortization and accretion | 102,864 | 97,094 | 291,558 | 216,888 | ||||||||||||
General and administrative | 18,840 | 12,560 | 45,562 | 33,188 | ||||||||||||
Total operating expenses | 200,901 | 168,786 | 545,511 | 382,730 | ||||||||||||
Operating income | 91,249 | 130,806 | 303,697 | 255,390 | ||||||||||||
Other income (expense): | ||||||||||||||||
Gain (loss) on commodity price risk management activities, net | 83,104 | (60,108 | ) | 2,009 | (53,185 | ) | ||||||||||
Interest income (expense), net | (26,857 | ) | (21,049 | ) | (76,981 | ) | (50,644 | ) | ||||||||
Other income (expense), net | (2 | ) | 1,001 | 53 | 1,683 | |||||||||||
Total other income (expense) | 56,245 | (80,156 | ) | (74,919 | ) | (102,146 | ) | |||||||||
Income before income taxes | 147,494 | 50,650 | 228,778 | 153,244 | ||||||||||||
Income tax expense | 55,300 | 19,500 | 86,300 | 58,400 | ||||||||||||
Net income | $ | 92,194 | $ | 31,150 | $ | 142,478 | $ | 94,844 | ||||||||
Earnings per common share: | ||||||||||||||||
Basic | $ | 0.34 | $ | 0.12 | $ | 0.53 | $ | 0.36 | ||||||||
Diluted | $ | 0.34 | $ | 0.12 | $ | 0.53 | $ | 0.35 | ||||||||
Weighted average common shares outstanding: | ||||||||||||||||
Basic | 267,480,116 | 265,733,881 | 266,837,348 | 265,500,414 | ||||||||||||
Diluted | 270,743,269 | 268,566,065 | 269,637,995 | 267,992,098 | ||||||||||||
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
4
KODIAK OIL & GAS CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
For the Nine Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
Cash flows from operating activities: | ||||||||
Net income | $ | 142,478 | $ | 94,844 | ||||
Reconciliation of net income to net cash provided by operating activities: | ||||||||
Depletion, depreciation, amortization and accretion | 291,558 | 216,888 | ||||||
Amortization of deferred financing costs and debt premium | 4,221 | 2,985 | ||||||
(Gain) loss on commodity price risk management activities, net | (2,009 | ) | 53,185 | |||||
Settlements on commodity derivative instruments | (43,618 | ) | (15,479 | ) | ||||
Stock‑based compensation | 15,041 | 11,105 | ||||||
Deferred income taxes | 86,300 | 58,400 | ||||||
Changes in current assets and liabilities: | ||||||||
Accounts receivable‑trade | 13,322 | (59,226 | ) | |||||
Accounts receivable‑accrued sales revenues | (15,591 | ) | (58,365 | ) | ||||
Prepaid expenses and other | (1,872 | ) | (1,159 | ) | ||||
Accounts payable and accrued liabilities | (5,215 | ) | 57,974 | |||||
Accrued interest payable | 5,645 | 24,383 | ||||||
Net cash provided by operating activities | 490,260 | 385,535 | ||||||
Cash flows from investing activities: | ||||||||
Acquired oil and gas properties and facilities | (6,000 | ) | (759,025 | ) | ||||
Oil and gas properties | (692,000 | ) | (767,814 | ) | ||||
Sale of oil and gas properties | 70,848 | 87,370 | ||||||
Equipment, facilities and other | (1,131 | ) | (25,517 | ) | ||||
Net cash used in investing activities | (628,283 | ) | (1,464,986 | ) | ||||
Cash flows from financing activities: | ||||||||
Borrowings under credit facility | 315,000 | 1,194,875 | ||||||
Repayments under credit facility | (153,000 | ) | (851,875 | ) | ||||
Proceeds from the issuance of senior notes | — | 750,000 | ||||||
Proceeds from the issuance of common shares | 8,239 | 2,283 | ||||||
Purchase of common shares | (2,760 | ) | (1,214 | ) | ||||
Debt and share issuance costs | — | (20,360 | ) | |||||
Net cash provided by financing activities | 167,479 | 1,073,709 | ||||||
Increase (decrease) in cash and cash equivalents | 29,456 | (5,742 | ) | |||||
Cash and cash equivalents at beginning of the period | 90 | 24,060 | ||||||
Cash and cash equivalents at end of the period | $ | 29,546 | $ | 18,318 | ||||
Supplemental cash flow information: | ||||||||
Oil & gas property accrual included in accounts payable and accrued liabilities | $ | 134,436 | $ | 201,438 | ||||
Cash paid for interest | $ | 90,363 | $ | 48,912 | ||||
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
5
KODIAK OIL & GAS CORP.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1—Organization
Description of Operations
Kodiak Oil & Gas Corp. 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. Kodiak Oil & Gas Corp. was incorporated (continued) in the Yukon Territory on September 28, 2001. The Company and its wholly-owned subsidiaries, Kodiak Oil & Gas (USA) Inc., KOG Finance, LLC, KOG Oil & Gas ULC and Kodiak Williston, LLC, are collectively referred to herein as “Kodiak” or the “Company”.
On July 13, 2014, the Company entered into an Arrangement Agreement (the "Arrangement Agreement") with Whiting Petroleum Corporation (“Whiting”) and a wholly-owned subsidiary of Whiting (“Whiting Canadian Sub”) whereby Whiting Canadian Sub would acquire all of the outstanding common shares as part of a plan of arrangement (the “Arrangement”). For further information on the Arrangement Agreement, please refer to Note 12 - Whiting Petroleum Corporation Arrangement Agreement.
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 subsidiaries. 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 Regulations 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 2013 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. There have been no material changes to the information disclosed in the notes to the consolidated financial statements included in Kodiak's 2013 Annual Report on Form 10-K.
Use of Estimates in the Preparation of Financial Statements
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 its estimates on an on-going basis and bases its 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 its estimates are reasonable.
6
Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update ("ASU") 2014-09, which establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method, and the standard will be effective for us in the first quarter of our fiscal year 2018; early adoption is not permitted. We are currently evaluating the impact of this new standard on our consolidated financial statements, as well as which transition method we intend to use.
In August 2014, the Financial Accounting Standards Board issued ASU 2014-15, which sets forth authoritative guidance that requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the entity’s financial statements are issued, or within one year after the date that the entity’s financial statements are available to be issued, and to provide disclosures when certain criteria are met. This guidance is effective for the annual period ending after December 15, 2016, early adoption is permitted. We are currently evaluating the impact of this new standard, however, we do not expect adoption to have a material impact on our consolidated financial statements.
Accounting standards that have been issued or proposed by the FASB or other standards-setting bodies that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.
Note 3—Acquisitions and Divestitures
July 2013 Acquisition
On July 12, 2013, the Company's wholly-owned subsidiary, Kodiak Williston, LLC, acquired an unaffiliated oil and gas company’s interests in approximately 42,000 net acres of Williston Basin leaseholds, and related producing properties located primarily in McKenzie and southern 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 "July 2013 Acquisition"). The seller received aggregate consideration of approximately $731.8 million in cash. The effective date for the acquisition was March 1, 2013, with purchase price adjustments calculated as of the closing date on July 12, 2013. The acquisition provided strategic additions adjacent to the Company's core project area and the acquired producing properties contributed revenue of $29.3 million and $92.3 million to the Company for the three and nine months ended September 30, 2014, respectively. Total transaction costs related to the acquisition incurred were approximately $235,000. Transaction costs are recorded in the statement of operations within the general and administrative expense line item.
7
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 July 12, 2013. In December 2013, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and final allocation of the fair value of assets acquired and liabilities assumed (in thousands):
Purchase Price | July 12, 2013 | |||
Consideration Given | ||||
Cash from credit facility | $ | 731,785 | ||
Total consideration given | $ | 731,785 | ||
Allocation of Purchase Price | ||||
Proved oil and gas properties | $ | 416,052 | ||
Unproved oil and gas properties | 292,518 | |||
Total fair value of oil and gas properties acquired | $ | 708,570 | ||
Working capital | $ | 25,442 | ||
Asset retirement obligation | (2,227 | ) | ||
Fair value of net assets acquired | $ | 731,785 | ||
Working capital acquired was estimated as follows: | ||||
Accounts receivable | $ | 61,271 | ||
Accrued liabilities | (35,829 | ) | ||
Total working capital | $ | 25,442 | ||
Pro Forma Financial Information
The following unaudited pro forma financial information represents the combined results for the Company and the properties acquired in July 2013 for the three and nine months ended September 30, 2013 as if the acquisition had occurred on January 1, 2012 (in thousands, except per share data). For purposes of the pro forma, it was assumed that the credit facility was utilized on January 1, 2012. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $1.0 million and $24.2 million for the three and nine months ended September 30, 2013, respectively. The pro forma information includes the effects of adjustments for amortization of financing costs of $26,000 and $434,000 for the three and nine months ended September 30, 2013, respectively. The pro forma information includes the effects of the incremental interest expense on acquisition financing of $600,000 and $5.9 million for the three and nine months ended September 30, 2013, respectively. The pro forma financial information includes total capitalization of interest expense of $9.7 million and $29.5 million for the three and nine months ended September 30, 2013, respectively. The pro forma information includes the effects of adjustments for income tax expense of $480,000 and $13.6 million for the three and nine months ended September 30, 2013, respectively.
8
The following pro forma results (in thousands, except share data) do not include any cost savings or other synergies that may result from the acquisition 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 acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results.
For the Three Months Ended September 30, 2013 | For the Nine Months Ended September 30, 2013 | |||||||
Operating revenues | $ | 302,692 | $ | 724,060 | ||||
Net income | $ | 31,935 | $ | 115,225 | ||||
Earnings per common share | ||||||||
Basic | $ | 0.12 | $ | 0.43 | ||||
Diluted | $ | 0.12 | $ | 0.43 | ||||
Divestitures
In the nine months ended September 30, 2014, the Company divested approximately 20,900 net acres in the Williston Basin for cash proceeds of $70.8 million.
Note 4—Long-Term Debt
As of the dates indicated, the Company’s long-term debt consisted of the following (in thousands):
September 30, 2014 | December 31, 2013 | |||||||
Credit Facility due April 2018 | $ | 870,000 | $ | 708,000 | ||||
2019 Notes due December 2019 | 800,000 | 800,000 | ||||||
Unamortized Premium on 2019 Notes | 4,459 | 4,976 | ||||||
2021 Notes due January 2021 | 350,000 | 350,000 | ||||||
2022 Notes due February 2022 | 400,000 | 400,000 | ||||||
Total Long-Term Debt | $ | 2,424,459 | $ | 2,262,976 | ||||
Less: Current Portion of Long Term Debt | — | — | ||||||
Total Long-Term Debt, Net of Current Portion | $ | 2,424,459 | $ | 2,262,976 | ||||
Credit Facility
Kodiak Oil & Gas (USA) Inc. (the “Borrower”) has in place a $1.5 billion credit facility with a syndicate of banks, which is subject to a borrowing base. The credit facility matures on April 2, 2018. As of September 30, 2014, the credit facility was subject to a borrowing base of $1.35 billion. Redetermination of the borrowing base occurs semi-annually, on April 1 and October 1. Additionally, the Company may elect a redetermination of the borrowing base one time during any six month period. In April 2014, the redetermination was completed and the existing borrowing base was affirmed. The Company has postponed the scheduled October 2014 redetermination until December 2014.
9
Interest on the credit facility is payable at one of the following two variable rates: the alternate base rate for ABR loans or the adjusted 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 credit 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 0.50% to 1.50%, depending on borrowing base usage. The Applicable Margin on the adjusted London interbank offered ("LIBO") rate is a sliding scale of 1.50% to 2.50%, depending on borrowing base usage. Additionally, the credit facility provides for 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 facility) as of 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 | 1.50 | % | 1.75 | % | 2.00 | % | 2.25 | % | 2.50 | % | |||||
ABR Loans | 0.50 | % | 0.75 | % | 1.00 | % | 1.25 | % | 1.50 | % | |||||
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 to 1.0 and to maintain, on the last day of each quarter, a ratio of total debt to EBITDAX of not greater than 4.0 to 1.0. The Company was in compliance with all financial covenants under the credit facility as of September 30, 2014, and through the filing of this report.
As of September 30, 2014, the Company had $870.0 million in outstanding borrowings under the credit facility and as such, the available credit under the credit facility at that date was $480.0 million. Subsequent to September 30, 2014, the Company made borrowings of $25.0 million to the credit facility, bringing the outstanding balance as of the date of this filing under the credit facility to $895.0 million. 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 commodity derivative instruments with several counterparties that are also lenders under the credit facility. The Company’s obligations under these derivative instruments are secured by the credit facility.
Senior Notes
In November 2011, the Company issued at par $650.0 million principal amount of 8.125% Senior Notes due December 1, 2019 and in May 2012, the Company issued at a price of 104.0% of par an additional $150.0 million aggregate principal amount of 8.125% Senior Notes due December 1, 2019 (the "2019 Notes"). The 2019 Notes bear an annual interest rate of 8.125%. The interest on the 2019 Notes is payable on June 1 and December 1 of each year. The issuance of the 2019 Notes resulted in aggregate net proceeds of approximately $784.2 million after deducting discounts and fees. The Company used the proceeds from the 2019 Notes to fund its acquisition program, repay outstanding borrowings under its credit facility and second lien credit agreement and for general corporate purposes.
In January 2013, the Company issued at par $350.0 million principal amount of 5.50% Senior Notes due January 15, 2021 (the "2021 Notes"). The 2021 Notes bear an annual interest rate of 5.50%. The interest on the 2021 Notes is payable on January 15 and July 15 of each year. The Company received net proceeds of approximately $343.1 million after deducting discounts and fees. All of the net proceeds from the 2021 Notes were used to repay borrowings on the Company's credit facility.
In July 2013, the Company issued at par $400.0 million principal amount of 5.50% Senior Notes due February 1, 2022 (the "2022 Notes" and, together with the 2019 Notes and 2021 Notes, the "Senior Notes"). The 2022 Notes bear an annual interest rate of 5.50%. The interest on the 2022 Notes is payable on February 1 and August 1 of each year commencing on February 1, 2014. The Company received net proceeds of approximately $391.8 million after deducting discounts and fees. All of the net proceeds from the 2022 Notes were used to repay borrowings on the Company's credit facility.
10
The 2019 Notes and 2021 Notes were issued under separate indentures among the Company, Kodiak Oil & Gas (USA) Inc., as guarantor, U.S. Bank National Association, as trustee, and Computershare Trust Company of Canada, as Canadian trustee (the “2019 Indenture” and the “2021 Indenture”, respectively). The 2022 Notes were issued under an indenture among the Company, Kodiak Oil & Gas (USA) Inc., Kodiak Williston, LLC and KOG Finance, LLC (collectively, the “Guarantors”), U.S. Bank National Association, as trustee, and Computershare Trust Company of Canada, as Canadian trustee (the “2022 Indenture”, and together with the 2019 Indenture and the 2021 Indenture, the “Indentures”). In July 2013, Kodiak Williston, LLC and KOG Finance, LLC entered into Supplemental Indentures to the 2019 Indenture and 2021 Indenture to guarantee the 2019 Notes and 2021 Notes. On October 3, 2014, KOG Oil & Gas ULC entered into Supplemental Indentures to guarantee the 2019 Notes, the 2021 Notes and the 2022 Notes. The Indentures contain affirmative and negative covenants that, among other things, limit the Company's and the Guarantors' 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 Indentures also contain 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 the Indentures as of September 30, 2014, and through the filing of this report.
The 2019 Notes are redeemable by the Company at any time on or after December 1, 2015, the 2021 Notes are redeemable by the Company at any time on or after January 15, 2017, and the 2022 Notes are redeemable by the Company at any time on or after August 1, 2017, in each case, at the redemption prices set forth in the indentures. Further, the 2019 Notes are redeemable by the Company prior to December 1, 2015, the 2021 Notes are redeemable by the Company prior to January 15, 2017, and the 2022 Notes are redeemable by the Company prior to August 1, 2017, in each case, at the redemption prices plus a “make-whole” premium set forth in the Indentures. The Company is also entitled to redeem up to 35% of the aggregate principal amount of the 2019 Notes before December 1, 2014, up to 35% of the aggregate principal amount of the 2021 Notes before January 15, 2016, and up to 35% of the aggregate principal amount of the 2022 Notes before August 1, 2016, with net proceeds that the Company raises in equity offerings at a redemption price equal to 108.125% of the principal amount of the 2019 Notes being redeemed and 105.5% of the principal amount of the 2021 Notes being redeemed and 105.5% of the principal amount of the 2022 Notes being redeemed, plus, in each case, accrued and unpaid interest. If the Company undergoes a change of control, it must offer to purchase the Senior Notes at a price equal to 101% of the principal amount of the Senior Notes purchased plus accrued and unpaid interest. The Company may redeem the Senior Notes if, as a result of changes in applicable law, it is required to pay additional amounts related to tax-withholdings, at a price equal to 100% of the principal amounts of the Senior Notes redeemed plus accrued and unpaid interest. The Company must offer to purchase the Senior Notes if it sells assets under certain circumstances.
On July 13, 2014, the Company entered into the Arrangement Agreement with Whiting and Whiting Canadian Sub whereby Whiting Canadian Sub would acquire all of the outstanding common shares as part of a plan of arrangement. In connection with the Arrangement, Whiting solicited and received the required consents of the holders of the Company’s outstanding Senior Notes, to adopt certain amendments to the Indentures (the “Consent Solicitations”). In connection with the Consent Solicitations, Whiting offered to (i) issue an unconditional and irrevocable guarantee (the “Whiting Guarantee”) of the prompt payment, when due, of any amount owed to the holders of the Senior Notes under the Senior Notes and the Indentures and any other amounts due pursuant to the Indentures and (ii) make a cash payment in respect of consents delivered in the Consent Solicitations (the “Consent Solicitations and Offers to Guarantee”). The Consent Solicitations and Offers to Guarantee expired at 5:00 p.m., New York City time, on October 17, 2014 and all required consents were received.
On October 17, 2014, the Company, Whiting, the Company’s subsidiary guarantors, U.S. Bank National Association, as trustee, and Computershare Trust Company of Canada, as Canadian trustee, entered into a supplemental indenture to each Indenture that includes the amendments to the Indenture and the Whiting Guarantee. These supplemental indentures became effective on October 17, 2014, but the amendments will not become operative and the Whiting Guarantee will not be issued until the completion of the Arrangement.
Deferred Financing Costs
As of September 30, 2014, the Company had deferred financing costs of $37.0 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 facility and Senior Notes. For the three and nine months ended September 30, 2014, the Company recorded
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amortization expense of $1.6 million and $4.7 million, respectively, as compared to $1.4 million and $3.5 million for the three and nine months ended September 30, 2013, respectively.
Interest Incurred On Long-Term Debt
For the three and nine months ended September 30, 2014, the Company incurred interest expense on long-term debt of $32.7 million and $96.1 million, respectively, as compared to $29.5 million and $73.3 million for the three and nine months ended September 30, 2013, respectively. Of the total interest incurred, the Company capitalized interest costs of $7.2 million and $23.2 million for the three and nine months ended September 30, 2014, respectively, as compared to $9.7 million and $25.6 million for the three and nine months ended September 30, 2013, respectively. Additionally, for the three and nine months ended September 30, 2014 interest expense was reduced for the amortization of the bond premium in the amounts of $176,000 and $517,000, respectively, as compared to $163,000 and $480,000 for the three and nine months ended September 30, 2013, respectively.
Note 5—Income Taxes
The Company computes its quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to its year-to-date income or loss plus any significant unusual or infrequently occurring items recorded in the interim period. The effective income tax rate for the nine months ended September 30, 2014 and 2013 was 37.7% and 38.1%, respectively. The Company's effective income tax rate for the nine months ended September 30, 2014 and 2013 differed from the U.S. statutory rate of 35% primarily due to state income taxes, estimated permanent differences and changes in the valuation allowance.
The Company continues to provide a full valuation allowance on the Canadian net deferred tax assets as ultimate realization of these deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment. As the Company does not have revenue generating assets in Canada, the Company does not expect to utilize the Canadian net deferred tax assets. The Company will continue to evaluate whether a valuation allowance on a separate country basis is needed in future reporting periods. Additionally, the Company has the ability and intends to indefinitely reinvest the undistributed earnings of Kodiak Oil & Gas (USA) Inc. with the exception of a de minimis amount of Canadian general and administrative expenses paid by Kodiak Oil & Gas (USA) Inc. on behalf of Kodiak Oil & Gas Corp.
The Company recognized income tax expense of $55.3 million and $86.3 million for the three and nine months ended September 30, 2014, respectively, as compared to $19.5 million and $58.4 million for the three and nine months ended September 30, 2013, respectively.
Accounting for Uncertainty in Income Taxes
As of September 30, 2014, the Company believes that it has no liability for uncertain tax positions. If the Company were to determine there were any uncertain tax positions, the Company would recognize the liability and related interest and penalties within income tax expense. As of September 30, 2014, the Company had no provision for interest or penalties related to uncertain tax positions. The Company files income tax returns in Canada and U.S. federal jurisdiction and various states. There are currently no Canadian or U.S. federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service, state or local tax authorities for tax years ended on or before December 31, 2009 or Canadian tax examinations by the Canadian Revenue Agency for tax years ended on or before December 31, 2002. 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.
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Note 6—Commodity Derivative Instruments
Through its wholly‑owned subsidiary Kodiak Oil & Gas (USA) Inc., the Company has entered into commodity derivative instruments, as described below. The Company has utilized swaps and “no premium” collars to reduce the effect of price changes on a portion of the Company's future oil production. A collar requires the Company to pay the counterparty if the settlement price is above the ceiling price and requires the counterparty to pay the Company if the settlement price is below the floor price. A swap requires the Company to pay the counterparty if the settlement price exceeds the strike price and the counterparty is required to pay the Company if the settlement price is less than the strike 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 eleven counterparties. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparties 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. The Company has not designated any of its derivative contracts as fair value or cash flow hedges. Therefore, the Company does not apply hedge accounting to its commodity derivative instruments. Net gains and losses on commodity price risk management activities are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on commodity price risk management activities are recorded in the commodity price risk management activities line on the consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows.
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.
The Company’s commodity derivative contracts as of September 30, 2014 are summarized below:
Collars | Basis (1) | Quantity (Bbl/d) | Strike Price ($/Bbl) | |||
Oct 1, 2014 - Dec 31, 2015 | NYMEX | 300 - 350 | $85.00 - $102.75 | |||
Swaps | Basis (1) | Average Quantity (Bbl/d) | Average Swap Price ($/Bbl) | |||
Oct 1, 2014 - Dec 31, 2014 Total | NYMEX | 25,800 | $93.41 | |||
Jan 1, 2015 - Jun 30, 2015 Total | NYMEX | 7,796 | $93.08 | |||
Jul 1, 2015 - Dec 31, 2015 Total | NYMEX | 3,291 | $91.17 | |||
(1) | NYMEX refers to quoted prices on the New York Mercantile Exchange |
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The following tables detail the fair value of the Company's derivative instruments, including the gross amounts and adjustments made to net the derivative instruments for presentation in the consolidated balance sheets (in thousands):
As of September 30, 2014 | ||||||||||||||
Underlying Commodity | Location on Balance Sheet | Gross Amounts of Recognized Assets and Liabilities | Gross Amounts Offset in the Consolidated Balance Sheet | Net Amounts of Assets and Liabilities Presented in the Consolidated Balance Sheet | ||||||||||
Crude oil derivative contract | Current assets | $ | 25,281 | $ | (1,605 | ) | $ | 23,676 | ||||||
Crude oil derivative contract | Noncurrent assets | $ | 3,120 | $ | (213 | ) | $ | 2,907 | ||||||
Crude oil derivative contract | Current liabilities | $ | 1,605 | $ | (1,605 | ) | $ | — | ||||||
Crude oil derivative contract | Noncurrent liabilities | $ | 213 | $ | (213 | ) | $ | — | ||||||
As of December 31, 2013 | ||||||||||||||
Underlying Commodity | Location on Balance Sheet | Gross Amounts of Recognized Assets and Liabilities | Gross Amounts Offset in the Consolidated Balance Sheet | Net Amounts of Assets and Liabilities Presented in the Consolidated Balance Sheet | ||||||||||
Crude oil derivative contract | Current assets | $ | 7,278 | $ | (7,278 | ) | $ | — | ||||||
Crude oil derivative contract | Noncurrent assets | $ | 2,731 | $ | (1,441 | ) | $ | 1,290 | ||||||
Crude oil derivative contract | Current liabilities | $ | 27,612 | $ | (7,278 | ) | $ | 20,334 | ||||||
Crude oil derivative contract | Noncurrent liabilities | $ | 1,441 | $ | (1,441 | ) | $ | — | ||||||
The Company recognized a net gain on commodity price risk management activities of $83.1 million and $2.0 million for the three and nine months ended September 30, 2014, respectively, as compared to a net loss on commodity price risk management activities of $60.1 million and $53.2 million for the three and nine months ended September 30, 2013, respectively.
Note 7—Asset Retirement Obligations
The Company follows accounting for asset retirement obligations in accordance with ASC 410, Asset Retirement and Environmental Obligations, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in wells at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement costs are depleted as a component of the full cost pool using the unit of production method.
For the Nine Months Ended September 30, 2014 | For the Year Ended December 31, 2013 | |||||||
Balance beginning of period | $ | 16,405 | $ | 9,064 | ||||
Liabilities incurred or acquired | 3,691 | 7,181 | ||||||
Liabilities settled or divested | (677 | ) | (890 | ) | ||||
Revisions in estimated cash flows | — | — | ||||||
Accretion expense | 1,138 | 1,050 | ||||||
Balance end of period | $ | 20,557 | $ | 16,405 | ||||
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Note 8—Fair Value Measurements
ASC Topic 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
• | Level 1: Quoted prices are available in active markets for identical assets or liabilities; |
• | Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; |
• | Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations. |
The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no significant assets or liabilities that were measured at fair value on a non-recurring basis in periods after initial recognition.
The Company’s non-recurring fair value measurements include asset retirement obligations, please refer to Note 7 - Asset Retirement Obligations, and the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to Note 3 - Acquisitions and Divestitures.
The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method.
The fair value of assets and liabilities acquired through business combinations is calculated using a discounted-cash flow approach using Level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices and operating costs.
The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2014 by level within the fair value hierarchy (in thousands):
Fair Value Measurements at September 30, 2014 | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
Financial Assets: | ||||||||||||||||
Commodity price risk management asset | $ | — | $ | 26,583 | $ | — | $ | 26,583 | ||||||||
Financial Liabilities: | ||||||||||||||||
Commodity price risk management liability | $ | — | $ | — | $ | — | $ | — | ||||||||
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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 September 30, 2014 and December 31, 2013, 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.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s credit facility approximates fair value as it bears interest at variable rates over the term of the loan. The fair value of the 2019 Notes, 2021 Notes and the 2022 Notes was derived from available market data. As such, the Company has classified these Senior Notes as Level 2. This disclosure (in thousands) does not impact the Company's financial position, results of operations or cash flows.
At September 30, 2014 | At December 31, 2013 | |||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
Credit facility | $ | 870,000 | $ | 870,000 | $ | 708,000 | $ | 708,000 | ||||||||
2019 Notes | $ | 804,459 | $ | 864,000 | $ | 804,976 | $ | 888,000 | ||||||||
2021 Notes | $ | 350,000 | $ | 355,250 | $ | 350,000 | $ | 350,438 | ||||||||
2022 Notes | $ | 400,000 | $ | 406,000 | $ | 400,000 | $ | 398,000 | ||||||||
Note 9—Share‑Based Payments
The Company has granted various equity-based awards to directors, officers, and employees of the Company under the 2007 Stock Incentive Plan, amended on June 3, 2010 and further amended on June 15, 2011 (as so amended, the “Plan”). The Plan authorizes the Company to issue stock options, stock appreciation rights, restricted stock and restricted stock units, performance awards, other stock grants and other stock‑based awards to any employee, consultant, independent contractor, director or officer providing services to the Company or to an affiliate of the Company. The maximum number of shares of common stock available for issuance under the Plan is equal to 14% of the Company’s issued and outstanding shares of common stock, as calculated on January 1 of each respective year, subject to adjustment as provided in the Plan. As of January 1, 2014, the maximum number of shares issuable under the Plan, including those previously issued thereunder, was approximately 37.3 million shares. Additionally, as a result of the Arrangement Agreement (please refer to Note 12 - Whiting Petroleum Corporation Arrangement Agreement for further details) the Company plans to vest stock options scheduled to vest on or before January 15, 2015 prior to the closing of the Arrangement. All unvested restricted stock and restricted stock units will vest upon the closing of the Arrangement.
Stock Options
Total compensation expense related to the stock options of $1.9 million and $6.6 million was recognized for the three and nine months ended September 30, 2014, respectively, as compared to $2.0 million and $5.7 million recognized for the three and nine months ended September 30, 2013, respectively. As of September 30, 2014, there was $7.6 million of total unrecognized compensation cost related to stock options, which is expected to be amortized over a weighted average period of 1.5 years.
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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:
For the Nine Months Ended September 30, 2014 | For the Year Ended December 31, 2013 | |||||||
Risk free rates | 1.65 - 2.03% | 0.88-2.14% | ||||||
Dividend yield | — | % | — | % | ||||
Expected volatility | 77.22 - 79.99% | 80.04 - 85.08% | ||||||
Weighted average expected stock option life | 5.58 years | 5.81 years | ||||||
The weighted average fair value at the date of grant for stock options granted is as follows: | ||||||||
Weighted average fair value per share | $ | 7.39 | $ | 6.80 | ||||
Total options granted | 1,270,100 | 1,850,900 | ||||||
Total weighted average fair value of options granted | $ | 9,386,039 | $ | 12,586,120 | ||||
A summary of the stock options outstanding is as follows:
Number of Options | Weighted Average Exercise Price | ||||||
Balance outstanding at January 1, 2014 | 6,100,155 | $ | 6.12 | ||||
Granted | 1,270,100 | $ | 11.00 | ||||
Canceled | (753,472 | ) | $ | 6.96 | |||
Exercised | (1,608,336 | ) | $ | 5.49 | |||
Balance outstanding at September 30, 2014 | 5,008,447 | $ | 7.43 | ||||
Options exercisable at September 30, 2014 | 3,013,814 | $ | 5.50 | ||||
The following table summarizes information about stock options outstanding at September 30, 2014:
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-$3.00 | 624,330 | 4.7 | $ | 1.92 | 624,330 | 4.7 | $ | 1.92 | ||||||||
$3.01-$6.00 | 1,042,377 | 2.7 | $ | 3.72 | 1,025,377 | 2.6 | $ | 3.70 | ||||||||
$6.01-$9.00 | 1,041,740 | 7.0 | $ | 7.65 | 643,740 | 6.3 | $ | 7.23 | ||||||||
$9.01-$12.00 | 2,033,000 | 8.6 | $ | 10.21 | 720,367 | 7.8 | $ | 9.60 | ||||||||
$12.01-$15.86 | 267,000 | 9.3 | $ | 12.84 | 0 | 0.0 | $ | 0.00 | ||||||||
5,008,447 | 6.6 | $ | 7.43 | 3,013,814 | 5.1 | $ | 5.50 | |||||||||
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The aggregate intrinsic value of vested and exercisable options as of September 30, 2014 was $24.3 million. The aggregate intrinsic value of options vested and expected to vest as of September 30, 2014 was $30.3 million. The intrinsic value is based on the Company’s September 30, 2014 closing common stock price of $13.57. This amount would have been received by the option holders had all option holders exercised their options as of that date. The total grant date fair value of the shares vested during the nine months ended September 30, 2014 was $7.4 million.
Restricted Stock and Restricted Stock Units
Total compensation expense related to restricted stock and restricted stock units (“RSUs”) of $2.8 million and $8.4 million was recognized for the three and nine months ended September 30, 2014, respectively, as compared to $1.9 million and $5.4 million was recognized for the three and nine months ended September 30, 2013, respectively. As of September 30, 2014, there was $11.3 million of total unrecognized compensation cost related to the restricted stock and the RSUs, which is expected to be amortized over a weighted average period of 1.9 years.
As of September 30, 2014, there were 1.3 million awarded and unvested performance based RSUs, 1.2 million RSU's that may be awarded subject to performance based metrics and 73,500 unvested restricted stock with a combined weighted average grant date fair value of $10.20 per share. The total fair value vested during the nine months ended September 30, 2014 was $212,000. A summary of the restricted stock and RSUs outstanding is as follows:
Number of Shares | Weighted Average Grant Date Fair Value | ||||||
Non-vested restricted stock and RSU's at January 1, 2014 | 2,613,175 | $ | 10.18 | ||||
Granted | — | — | |||||
Forfeited | (29,000 | ) | 9.49 | ||||
Vested | (22,500 | ) | 9.42 | ||||
Non-vested restricted stock and RSUs at September 30, 2014 | 2,561,675 | $ | 10.20 | ||||
Note 10—Earnings Per Share
Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted average number of common shares outstanding during the reporting period. Diluted net income per common share includes shares of restricted stock units, and the potential dilution that could occur upon exercise of options to acquire common stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the proceeds from the exercise of the options (which were assumed to have been made at the average market price of the common shares during the reporting period).
In accordance with ASC 260-10-45, Share‑Based Payment Arrangements and Participating Securities and the Two-Class Method, the Company’s unvested restricted stock shares are deemed participating securities, since these shares would be entitled to participate in dividends declared on common shares. During periods of net income, the calculation of earnings per share for common stock exclude income attributable to the restricted stock shares from the numerator and exclude the dilutive impact of those shares from the denominator. During periods of net loss, no effect is given to the participating securities because they do not share in the losses of the Company.
The performance-based restricted stock units and unexercised stock options are not participating securities, since these shares are not entitled to participate in dividends declared on common shares. The number of potentially dilutive shares attributable to the performance based restricted stock units is based on the number of shares, if any, which would be issuable at the end of the respective reporting period, assuming that date was the end of the performance measurement period. Please refer to Note 9 - Share Based Payments under the heading "Restricted Stock and Restricted Stock Units" for additional discussion.
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The table below sets forth the computations of basic and diluted net income per share for the three and nine months ended September 30, 2014 and 2013 (in thousands, except per share data):
For the Three Months Ended September 30, | For the Nine Months Ended September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Basic net income | $ | 92,194 | $ | 31,150 | $ | 142,478 | $ | 94,844 | ||||||||
Income allocable to participating securities | (25 | ) | (4 | ) | (39 | ) | (13 | ) | ||||||||
Diluted net income | $ | 92,169 | $ | 31,146 | $ | 142,439 | $ | 94,831 | ||||||||
Basic weighted average common shares outstanding | 267,480,116 | 265,733,881 | 266,837,348 | 265,500,414 | ||||||||||||
Effect of dilutive securities | ||||||||||||||||
Options to purchase common shares | 5,006,447 | 5,616,655 | 4,948,447 | 4,546,155 | ||||||||||||
Assumed treasury shares purchased | (3,151,158 | ) | (3,745,681 | ) | (3,319,413 | ) | (2,828,113 | ) | ||||||||
Unvested restricted stock units | 1,407,864 | 961,210 | 1,171,613 | 773,642 | ||||||||||||
Diluted weighted average common shares outstanding | 270,743,269 | 268,566,065 | 269,637,995 | 267,992,098 | ||||||||||||
Basic net income per share | $ | 0.34 | $ | 0.12 | $ | 0.53 | $ | 0.36 | ||||||||
Diluted net income per share | $ | 0.34 | $ | 0.12 | $ | 0.53 | $ | 0.35 | ||||||||
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 September 30, | For the Nine Months Ended September 30, | |||||||||
2014 | 2013 | 2014 | 2013 | |||||||
Anti-dilutive shares | 2,000 | 256,500 | 60,000 | 1,327,000 | ||||||
Note 11—Commitments and Contingencies
Lease Obligations
The Company leases office space in Denver, Colorado and Williston and Dickinson, North Dakota under separate operating lease agreements. The Denver, Colorado lease expires on October 31, 2016. The Williston and Dickinson, North Dakota leases expire on January 31, 2017 and December 31, 2014, respectively. Total rental commitments under non-cancelable leases for office space were $2.8 million at September 30, 2014. The future minimum lease payments under these non-cancelable leases are as follows: $300,000 in 2014, $1.3 million in 2015, $1.2 million in 2016, and $0 thereafter.
Drilling Rigs
As of September 30, 2014, the Company was subject to commitments on its drilling rigs. In the event of early termination under all of the contracts, the Company would be obligated to pay an aggregate amount of approximately $42.8 million as of September 30, 2014 as required under the varying terms of the contracts.
Guarantees of the Senior Notes
As of September 30, 2014, the Company had issued $800.0 million of 2019 Notes, $350.0 million of 2021 Notes, and $400.0 million of 2022 Notes, all of which are guaranteed on a senior unsecured basis by the Company's wholly-owned subsidiaries, Kodiak Oil & Gas (USA) Inc., Kodiak Williston, LLC and KOG Finance, LLC. Kodiak Oil & Gas Corp, as the parent company, has no independent assets or operations. The guarantees are full, unconditional, and joint and several. KOG Oil & Gas ULC, the Company's non-guarantor subsidiary, as of September 30, 2014, has de minimis operations. On October 3, 2014, KOG Oil & Gas ULC guaranteed the 2019 Notes, the 2021 Notes and the 2022 Notes on a senior unsecured basis.
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Under the Company’s credit facility and the Indentures, the Company and subsidiary guarantors are subject to certain limitations on the ability of the subsidiary guarantors to transfer funds to the Company, including certain limitations on dividends, distributions, redemptions, payments, investments, loans and advances. There are no other restrictions on the ability of the Company to obtain funds from its subsidiaries by dividend or loan (other than as described in Note 4 - Long-Term Debt). Finally, as of the most recent fiscal year end, other than as described above, the parent Company’s wholly‑owned subsidiary does not have restricted assets that exceed 25% of consolidated net assets that may not be transferred to the Company in the form of loans, advances, or cash dividends by the subsidiaries without the consent of a third party.
The Company may issue additional debt securities in the future that the Company's wholly‑owned subsidiaries, Kodiak Oil & Gas (USA) Inc., Kodiak Williston, LLC, KOG Finance, LLC and KOG Oil & Gas ULC may guarantee. Any such guarantees are expected to be full, unconditional, and joint and several. As stated above, the Company has no independent assets or operations, and, other than as described herein, there are no significant restrictions on the ability of the Company to receive funds from the Company's subsidiaries through dividends, loans, and advances or otherwise.
Other
The Company is subject to litigation and claims in pending or threatened legal proceedings arising in the normal course of its business, including, but not limited to, royalty claims and contract claims. The Company believes all such matters are without merit or involve amounts which, if resolved unfavorably, either individually or in the aggregate, will not have a material adverse effect on its financial condition, results of operations or cash flows.
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.
Note 12—Whiting Petroleum Corporation Arrangement Agreement
On July 13, 2014, the Company entered into the Arrangement Agreement, among the Company, Whiting and Whiting Canadian Sub, pursuant to which Whiting Canadian Sub will acquire all of the outstanding common shares, without par value per share, of the Company (the “Kodiak Common Shares”) and Whiting Canadian Sub and the Company will amalgamate to form one corporate entity with the Company surviving the amalgamation as part of a plan of arrangement.
Subject to the terms and conditions of the Arrangement Agreement, at the effective time of the Arrangement, each outstanding Kodiak Common Share, other than Kodiak Common Shares with respect to which dissent rights have been properly exercised and not withdrawn (the “Dissenting Shares”), will be exchanged for 0.177 of a share (the “Share Exchange Ratio”) of Whiting common stock, $0.001 par value per share (the “Whiting Common Stock”). Each outstanding stock option to purchase Kodiak Common Shares, restricted stock unit measured in relation to, or settleable in, Kodiak Common Shares and each award of restricted stock relating to Kodiak Common Shares, whether vested or unvested, will be assumed by Whiting and converted automatically at the effective time of the Arrangement into an option, restricted stock unit or restricted stock award, as the case may be, denominated in shares of Whiting Common Stock based on the Share Exchange Ratio and subject to terms and conditions substantially identical to those in effect at the effective time of the Arrangement.
The closing of the Arrangement is subject to satisfaction of certain conditions, including, among others: (i) approval of the Company’s and Whiting’s shareholders; (ii) approval by the Supreme Court of British Columbia (the “Applicable Court”); (iii) the expiration or termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”); (iv) the accuracy of representations and warranties of, and compliance with covenants by, the other party; and (v) no more than 5% of the shares of Kodiak Common Shares being Dissenting Shares.
Early termination of the waiting period under the HSR Act was granted on August 5, 2014. On October 22, 2014, the Company obtained an interim order from the British Columbia Supreme Court authorizing, among other procedural matters, the calling and holding of a special meeting of the Company’s securityholders to be held on December 3, 2014 at 8:00 am Mountain Time to vote on matters related to the proposed Arrangement.
The Company and Whiting have made customary representations, warranties and covenants in the Arrangement Agreement, including, among other things, covenants (i) with respect to the conduct of their respective businesses during the interim period between the execution of the Arrangement Agreement and consummation of the Arrangement and (ii)
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prohibiting each of the Company and Whiting from soliciting alternative acquisition proposals and providing information to or engaging in discussions with third-parties, except in the limited circumstances as provided in the Arrangement Agreement.
The Arrangement Agreement contains certain termination rights for both the Company and Whiting including, but not limited to, in the event that (i) the Arrangement has not been consummated on or prior to the date that is 180 days after the date of the Arrangement Agreement (subject to an automatic extension of up to 60 additional days to satisfy the conditions related to the expiration or termination of the waiting period under the HSR Act); (ii) the other party materially breaches its representations or covenants and such breach is not, or is not capable of being, cured within 30 days of notice; (iii) the Applicable Court fails to approve the Arrangement, (iv) the Company’s or Whiting’s shareholders fail to approve the Arrangement; or (v) the other party’s board of directors makes an Adverse Recommendation Change (as defined in the Arrangement Agreement), or fails to reaffirm its recommendation following receipt of an acquisition proposal. In addition, prior to obtaining shareholder approval of the Arrangement and subject to the payment of a termination fee, the Company and Whiting each may terminate the Arrangement Agreement in order to enter into an agreement for a Superior Proposal (as defined in the Arrangement Agreement). Upon termination of the Arrangement Agreement, under specified circumstances (including in connection with an Adverse Recommendation Change or a Superior Proposal), either the Company or Whiting will be obligated to pay to the other party a termination fee of $130.0 million and reimburse up to $10.0 million of the other party’s expenses. If the Arrangement Agreement is terminated because a party’s shareholders do not approve the transaction, such party will be obligated to reimburse up to $10.0 million of the other party’s expenses. As of September 30, 2014, the Company has incurred transaction costs of $6.8 million to complete the Arrangement Agreement.
Whiting will take all necessary corporate action to appoint Lynn A. Peterson, the President and Chief Executive Officer and a director of the Company, and James E. Catlin, the Executive Vice President of Business Development and a director of the Company, to the Board of Directors of Whiting as of the effective time of the Arrangement.
Subsequent to the announcement of the Arrangement, seven purported class action lawsuits have been filed on behalf of the Company's shareholders in the United States District Court for the District of Colorado: Quigley and Koelling v.Whiting Petroleum Corporation, et al., Case No. 1:14-cv-02023, filed July 22, 2014 (the plaintiffs voluntarily dismissed this lawsuit on September 24, 2014); Fioravanti v. Krysiak, et al., Case No. 1:14-cv-02037, filed July 23, 2014 (the plaintiffs voluntarily dismissed this lawsuit October 24, 2014); Wilkinson v.Whiting Petroleum Corporation, et al., Case No. 1:14-cv-2074, filed July 25, 2014 (the plaintiffs voluntarily dismissed this lawsuit on October 23, 2014); Goldsmith v. Krysiak, et al., Case No. 1:14-cv-2098, filed July 29, 2014 (the plaintiffs voluntarily dismissed this lawsuit on October 31, 2014); Rogowski v.Whiting Petroleum Corporation, et al., Case No. 1:14-cv-2136, filed July 31, 2014 (the plaintiffs voluntarily dismissed this lawsuit on October 20, 2014); Reiter v. Peterson, et al., Case No. 1:14-cv-02176, filed August 6, 2014; Sohler v. Whiting Petroleum Corporation, et al., Case No. 1:14-cv-02863, filed October 20, 2014 (the “Sohler Case”); and one purported class action lawsuit has been filed on behalf of the Company's shareholders in Denver District Court, State of Colorado: The Booth Family Trust v. Kodiak Oil & Gas Corp., et al., Case No. 14-cv-32947, filed July 25, 2014. This last case was removed to the United States District Court for the District of Colorado on September 4, 2014 and is pending in that court now as Case No. 1:14-cv-2457. It is possible that other related or amended suits could subsequently be filed. The defendants have filed motions to dismiss with prejudice in the all remaining cases other than the Sohler Case. The allegations in the three remaining lawsuits are similar. They purport to be brought as class actions on behalf of all shareholders of the Company. The complaints name as defendants the individual members of the Company's board of directors, Whiting and Whiting Canadian Sub and list the Company as a nominal party or a defendant. The complaints allege that the Company's board of directors breached its fiduciary duties to the Company's shareholders by, among other things, failing to engage in a fair sale process before approving the Arrangement and to maximize shareholder value in connection with the Arrangement. Additionally, the Sohler Case alleges violations under Sections 14(a) and 20(a) of the Exchange Act and SEC Rule 14a-9 promulgated thereunder. Specifically, the complaints allege that the Company's board of directors undervalued the Company in connection with the Arrangement and that the Company's board of directors agreed to certain deal protection mechanisms that precluded the Company from obtaining competing offers. The complaints also allege that Whiting and Whiting Canadian Sub aided and abetted the Company's board of directors’ alleged breaches of fiduciary duties. The Sohler Case alleges additionally that in issuing the preliminary joint proxy statement/circular the Company's board of directors violated the cited sections of and rule promulgated under the Exchange Act. The complaints seek, among other things, injunctive relief preventing the closing of the Arrangement, rescission of the Arrangement or an award of rescissory damages to the purported class in the event that the Arrangement is consummated, and damages, including counsel fees and expenses. Whiting and the Company believe each lawsuit is without merit.
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Forward-Looking Statements
The information discussed in this quarterly report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, our financial position, business strategy, consummation of the proposed Arrangement 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 those detailed in the section entitled “Risk Factors” included in our Annual Report on Form 10-K and under Item 1A "Risk Factors" of this quarterly report on Form 10-Q. 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 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.
Whiting Petroleum Corporation Arrangement Agreement
On July 13, 2014, we entered into the Arrangement Agreement, among the Company, Whiting and Whiting Canadian Sub, pursuant to which Whiting Canadian Sub will acquire all of the outstanding Kodiak Common Shares and Whiting Canadian Sub and the Company will amalgamate to form one corporate entity with the Company surviving the amalgamation as part of a plan of arrangement.
Subject to the terms and conditions of the Arrangement Agreement, at the effective time of the Arrangement, each outstanding Kodiak Common Share, other than Dissenting Shares, will be exchanged for the Share Exchange Ratio of 0.177 of a share of Whiting Common Stock. Each outstanding stock option to purchase Kodiak Common Shares, restricted stock unit measured in relation to, or settleable in, Kodiak Common Shares and each award of restricted stock relating to Kodiak Common Shares, whether vested or unvested, will be assumed by Whiting and converted automatically at the effective time of the Arrangement into an option, restricted stock unit or restricted stock award, as the case may be, denominated in shares of Whiting Common Stock based on the Share Exchange Ratio and subject to terms and conditions substantially identical to those in effect at the effective time of the Arrangement.
The closing of the Arrangement is subject to satisfaction of certain conditions, including, among others: (i) approval of the Company's and Whiting’s shareholders; (ii) approval by the Supreme Court of British Columbia; (iii) the expiration or termination of the waiting period under the HSR Act; (iv) the accuracy of representations and warranties of, and compliance with covenants by, the other party; and (v) no more than 5% of the shares of Kodiak Common Shares being Dissenting Shares. The closing of the Arrangement is expected to be completed in the fourth quarter of 2014.
Early termination of the waiting period under the HSR Act was granted on August 5, 2014. On October 22, 2014, we obtained an interim order from the British Columbia Supreme Court authorizing, among other procedural matters, the calling and holding of a special meeting of our securityholders to be held on December 3, 2014 at 8:00 am Mountain Time to vote on matters related to the proposed Arrangement.
The Company and Whiting have made customary representations, warranties and covenants in the Arrangement Agreement, including, among other things, covenants (i) with respect to the conduct of their respective businesses during the interim period between the execution of the Arrangement Agreement and consummation of the Arrangement and (ii) prohibiting each of the Company and Whiting from soliciting alternative acquisition proposals and providing information to or engaging in discussions with third-parties, except in the limited circumstances as provided in the Arrangement Agreement.
The Arrangement Agreement contains certain termination rights for both the Company and Whiting including, but not limited to, in the event that (i) the Arrangement has not been consummated on or prior to the date that is 180 days after
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the date of the Arrangement Agreement (subject to an automatic extension of up to 60 additional days to satisfy the conditions related to the expiration or termination of the waiting period under the HSR Act); (ii) the other party materially breaches its representations or covenants and such breach is not, or is not capable of being, cured within 30 days of notice; (iii) the Applicable Court fails to approve the Arrangement, (iv) the Company's or Whiting’s shareholders fail to approve the Arrangement; or (v) the other party’s board of directors makes an Adverse Recommendation Change (as defined in the Arrangement Agreement), or fails to reaffirm its recommendation following receipt of an acquisition proposal. In addition, prior to obtaining shareholder approval of the Arrangement and subject to the payment of a termination fee, the Company and Whiting each may terminate the Arrangement Agreement in order to enter into an agreement for a Superior Proposal (as defined in the Arrangement Agreement). Upon termination of the Arrangement Agreement, under specified circumstances (including in connection with an Adverse Recommendation Change or a Superior Proposal), either the Company or Whiting will be obligated to pay to the other party a termination fee of $130.0 million and reimburse up to $10.0 million of the other party’s expenses. If the Arrangement Agreement is terminated because a party’s shareholders do not approve the transaction, such party will be obligated to reimburse up to $10.0 million of the other party’s expenses. We will incur transaction costs in order to complete the Arrangement Agreement, which may be substantial.
Whiting will take all necessary corporate action to appoint Lynn A. Peterson, the President and Chief Executive Officer and a director of the Company, and James E. Catlin, the Executive Vice President of Business Development and a director of the Company, to the Board of Directors of Whiting as of the effective time of the Arrangement.
Subsequent to the announcement of the Arrangement, seven purported class action lawsuits have been filed on behalf of the Company's shareholders in the United States District Court for the District of Colorado: Quigley and Koelling v.Whiting Petroleum Corporation, et al., Case No. 1:14-cv-02023, filed July 22, 2014 (the plaintiffs voluntarily dismissed this lawsuit on September 24, 2014); Fioravanti v. Krysiak, et al., Case No. 1:14-cv-02037, filed July 23, 2014 (the plaintiffs voluntarily dismissed this lawsuit October 24, 2014); Wilkinson v.Whiting Petroleum Corporation, et al., Case No. 1:14-cv-2074, filed July 25, 2014 (the plaintiffs voluntarily dismissed this lawsuit on October 23, 2014); Goldsmith v. Krysiak, et al., Case No. 1:14-cv-2098, filed July 29, 2014 (the plaintiffs voluntarily dismissed this lawsuit on October 31, 2014); Rogowski v.Whiting Petroleum Corporation, et al., Case No. 1:14-cv-2136, filed July 31, 2014 (the plaintiffs voluntarily dismissed this lawsuit on October 20, 2014); Reiter v. Peterson, et al., Case No. 1:14-cv-02176, filed August 6, 2014; Sohler v. Whiting Petroleum Corporation, et al., Case No. 1:14-cv-02863, filed October 20, 2014 (the “Sohler Case”); and one purported class action lawsuit has been filed on behalf of the Company's shareholders in Denver District Court, State of Colorado: The Booth Family Trust v. Kodiak Oil & Gas Corp., et al., Case No. 14-cv-32947, filed July 25, 2014. This last case was removed to the United States District Court for the District of Colorado on September 4, 2014 and is pending in that court now as Case No. 1:14-cv-2457. It is possible that other related or amended suits could subsequently be filed. The defendants have filed motions to dismiss with prejudice in the all remaining cases other than the Sohler Case. The allegations in the three remaining lawsuits are similar. They purport to be brought as class actions on behalf of all shareholders of the Company. The complaints name as defendants the individual members of the Company's board of directors, Whiting and Whiting Canadian Sub and list the Company as a nominal party or a defendant. The complaints allege that the Company's board of directors breached its fiduciary duties to the Company's shareholders by, among other things, failing to engage in a fair sale process before approving the Arrangement and to maximize shareholder value in connection with the Arrangement. Additionally, the Sohler Case alleges violations under Sections 14(a) and 20(a) of the Exchange Act and SEC Rule 14a-9 promulgated thereunder. Specifically, the complaints allege that the Company's board of directors undervalued the Company in connection with the Arrangement and that the Company's board of directors agreed to certain deal protection mechanisms that precluded the Company from obtaining competing offers. The complaints also allege that Whiting and Whiting Canadian Sub aided and abetted the Company's board of directors’ alleged breaches of fiduciary duties. The Sohler Case alleges additionally that in issuing the preliminary joint proxy statement/circular the Company's board of directors violated the cited sections of and rule promulgated under the Exchange Act. The complaints seek, among other things, injunctive relief preventing the closing of the Arrangement, rescission of the Arrangement or an award of rescissory damages to the purported class in the event that the Arrangement is consummated, and damages, including counsel fees and expenses. Whiting and the Company believe each lawsuit is without merit.
If the Arrangement is consummated, our future strategy will be determined by Whiting's board of directors and management. As a result, Item 2 of this Form 10-Q addresses our current strategy, which would be subject to change following the consummation of the Arrangement.
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Overview
We are an independent energy company focused on the exploration, exploitation, acquisition and production of crude oil and natural gas in the Rocky Mountain region of 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 drilling opportunities within a high-potential resource play. We intend to continue to expand our asset base by drilling and completing wells within our current lands as well as evaluating and investing in core acquisitions.
Our oil and natural gas reserves and operations are primarily concentrated in the Williston Basin of North Dakota, where the principal target of drilling is the Bakken shale hydrocarbon system highlighted by production from the Middle Bakken member, located between two Bakken shales that serve as the source rock, and the Three Forks Formation, positioned immediately below the lower Bakken shale. As of September 30, 2014, we owned an interest in approximately 307,000 gross (171,000 net) acres in the Williston Basin and have an interest in 739 gross (294.7 net) producing wells in the Williston Basin.
Recent Developments
Operational Update
We currently operate seven drilling rigs, which have staggered contract terminations, allowing us to adjust our rig count to align with our cash flow and capital expenditure projections. During the quarter ended September 30, 2014, we began upgrading our rig fleet. Two rig contracts were terminated during the third quarter of 2014 and were replaced by newly built rigs that were delivered late in the third quarter and early in the fourth quarter of 2014. These new build rigs require fewer loads during field moves and should be more efficient. As a result of our rig upgrade, we operated with five rigs for part of the third quarter of 2014 resulting in fewer wells drilled and therefore fewer wells completed in the second half of the year.
The following table summarizes the wells spud and completed during the three and nine months ended September 30, 2014:
For the Three Months Ended September 30, 2014 | ||||||||||||
Spud | Completed | |||||||||||
Gross | Net | Gross | Net | |||||||||
Operated wells | 22 | 16.1 | 27 | 18.3 | ||||||||
Non-operated wells | 17 | 1.1 | 22 | 2.5 | ||||||||
39 | 17.2 | 49 | 20.8 | |||||||||
For the Nine Months Ended September 30, 2014 | ||||||||||||
Spud | Completed | |||||||||||
Gross | Net | Gross | Net | |||||||||
Operated wells | 70 | 51.6 | 72 | 53.4 | ||||||||
Non-operated wells | 72 | 6.5 | 84 | 9.8 | ||||||||
142 | 58.1 | 156 | 63.2 | |||||||||
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Liquidity and Capital Resources
2014 Capital Expenditures Budget
Our 2014 capital expenditures budget is subject to various factors, including market conditions, oil field services and equipment availability, commodity prices and drilling results. As a result of our rig upgrade described above, we expect to drill and complete fewer total wells and spend less in capital expenditures in the second half of 2014 than originally estimated. The following table summarizes our original 2014 capital expenditures budget and our actual capital expenditures, including accruals, for the nine months ended September 30, 2014 (in millions):
Nine Months Ended | ||||||||
Annual | September 30, 2014 | |||||||
2014 Budget | Actual | |||||||
Capital Expenditures | ||||||||
Drilling and completion costs | $ | 890.0 | $ | 632.5 | ||||
Infrastructure and leasehold acquisitions | 50.0 | 10.8 | ||||||
Total capital expenditures | $ | 940.0 | $ | 643.3 | ||||
Divestitures | ||||||||
Proved and unproved oil and gas properties | $ | (70.8 | ) | |||||
Non-Cash Capitalized Costs | ||||||||
Asset retirement obligations | $ | 3.2 | ||||||
Capitalized interest | 23.2 | |||||||
Total capitalized costs, net of divestitures | $ | 598.9 | ||||||
For the nine months ended September 30, 2014, we incurred capital expenditures of $643.3 million related to our oil field operations to complete 63.2 net wells.
Sources of Capital
Cash flow from operations. We expect our cash flow from operations to continue to increase commensurate with our anticipated increase in sales volumes. We have been able to increase our volumes on an annual basis since we began our operations in the Bakken play in 2009. If we are able to continue to drill and complete our wells as anticipated and they produce at rates similar to those generated by our existing wells, subject to the changes in the market price of crude oil, we would expect our production rates and operating cash flows to continue to increase as we continue to develop our properties.
Credit facility. As of September 30, 2014, our maximum credit available under the credit facility was $1.5 billion with a borrowing base and aggregate commitments of $1.35 billion. As of September 30, 2014, we had available borrowings under the credit facility of $480.0 million. In April 2014, we completed our semi-annual redetermination which affirmed the borrowing base and aggregate commitments of $1.35 billion. We have postponed the scheduled October 2014 redetermination until December 2014.
As of the date of this filing, we have $895.0 million outstanding under this credit facility, with available borrowings of $455.0 million. The ability to maintain and increase this facility and borrow additional funds is dependent on a number of variables, including our proved reserves, and assumptions regarding the price at which oil and natural gas can be sold. Further, we expect that our borrowing base will increase with the addition of proved properties resulting from our ongoing drilling and completion activities. We are subject to restrictive covenants under the credit facility. For further details on our credit facility, please refer to Note 4 - Long-Term Debt under Item 1 in this Quarterly Report.
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Capital Requirements Outlook
We are dependent on our anticipated cash flows from operations and, to a lesser extent, the expected borrowing availability under our credit facility to fund our remaining 2014 capital expenditures budget, our obligations under our Senior Notes and other contractual commitments (please refer to Note 4 - Long-Term Debt and Note 11 - Commitments and Contingencies under Item 1 in this Quarterly Report for further details). While we expect such sources of capital to be sufficient for such purposes, there can be no assurance that we will achieve our anticipated future cash flows from operations, that credit will be available under our credit facility when needed, or that we would be able to complete alternative transactions in the capital markets, if needed. Our ability to obtain financing on commercially reasonable terms is dependent on a number of factors, many of which we cannot control, including changes in our credit rating, interest rates, market perceptions of us and the oil and natural gas exploration and production industry and tax burdens due to new tax laws.
If our existing and potential sources of liquidity are not sufficient to satisfy such commitments and to undertake our currently planned expenditures, we believe that we have the flexibility in our commitments to alter our development program. We operate the majority of our leasehold; therefore, we have the ability to adjust our drilling schedule to reflect a change in commodity prices or oilfield service environment. At this time the majority of our leasehold is held by production.
Senior Notes
As of the date of this filing we have $800.0 million outstanding under our 8.125% Senior Notes due in December 2019, $350.0 million outstanding under our 5.50% Senior Notes due in January 2021 and $400.0 million outstanding under our 5.50% Senior Notes due in February 2022. The annualized interest to be incurred under all of the Senior Notes is approximately $106.3 million.
On July 13, 2014, we entered into the Arrangement Agreement with Whiting and Whiting Canadian Sub whereby Whiting Canadian Sub would acquire all of the outstanding Kodiak Common Shares as part of a plan of arrangement. In connection with the Arrangement, Whiting solicited and received the required consents through its Consent Solicitations of the holders of our Senior Notes, to adopt certain amendments to the Indentures under which the Senior Notes were issued. In connection with the Consent Solicitations, Whiting offered to (i) issue an unconditional and irrevocable Whiting Guarantee of the prompt payment, when due, of any amount owed to the holders of the Senior Notes under the Senior Notes and the Indentures and any other amounts due pursuant to the Indentures and (ii) make a cash payment in respect of consents delivered in the Consent Solicitations (the “Consent Solicitations and Offers to Guarantee”). The Consent Solicitations and Offers to Guarantee expired at 5:00 p.m., New York City time, on October 17, 2014 and all required consents were received.
On October 17, 2014, the Company, Whiting, the Company’s subsidiary guarantors, U.S. Bank National Association, as trustee, and Computershare Trust Company of Canada, as Canadian trustee, entered into a supplemental indenture to each Indenture that includes the amendments to the Indenture and the Whiting Guarantee. These supplemental indentures became effective on October 17, 2014, but the amendments will not become operative and the Whiting Guarantee will not be issued until the completion of the Arrangement.
For further discussion regarding our Senior Notes, please refer to Note 4 - Long-Term Debt under Item 1 in this Quarterly Report.
Working Capital
The measure of working capital is less meaningful to understanding our financial position because of the availability of our borrowing base (as described above in "Credit facility"). As part of our cash management strategy, we frequently use available funds to reduce any balance on our credit facility. Because of this, we generally maintain low cash and cash equivalent balances. Additionally, since our principal source of operating cash flows (proved reserves to be produced in future years) is not considered working capital, we often have negative working capital. Our working capital was $32.7 million at September 30, 2014, as compared to a deficit of $61.1 million at December 31, 2013.
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Registered Offerings
Historically, we have financed our operations, property acquisitions and other capital investments in part from the proceeds from offerings of our equity and debt securities. We may from time to time offer 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.
Derivative Instruments
We utilize various derivative instruments in connection with anticipated crude oil sales to minimize the impact of product price fluctuations and ensure cash flow for future capital needs. Currently, we utilize swaps and “no premium” collars. Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. If actual commodity prices are higher than the fixed or ceiling prices in our derivative instruments, our cash flows will be lower than if we had no derivative instruments. Conversely, if actual commodity prices are lower than the fixed or floor prices in our derivative instruments, our cash flows will be higher than if we had no derivative instruments.
Cash Flow Analysis
The following is a summary of our change in cash and cash equivalents for the nine months ended September 30, 2014 and 2013 (in thousands):
For the Nine Months Ended September 30, | Period to period change | |||||||||||
2014 | 2013 | |||||||||||
Net cash provided by operating activities | $ | 490,260 | $ | 385,535 | $ | 104,725 | ||||||
Net cash used in investing activities | (628,283 | ) | (1,464,986 | ) | 836,703 | |||||||
Net cash provided by financing activities | 167,479 | 1,073,709 | (906,230 | ) | ||||||||
Increase (decrease) in cash and cash equivalents | $ | 29,456 | $ | (5,742 | ) | $ | 35,198 | |||||
Net cash provided by operating activities. The key component of our net cash provided by operating activities is the revenue derived from our crude oil sales and the crude oil prices received for those sales. For the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013, our net cash provided by operating activities increased by $104.7 million, primarily due to the increase in crude oil sales volumes of approximately 2.4 million barrels. Our revenues are directly affected by oil and natural gas commodity prices, which can fluctuate dramatically. The commodity prices are largely beyond our control and are difficult to predict. We have seen significant volatility in oil and natural gas prices in recent years. As such, we utilize derivative instruments, as further discussed under the heading "Operating Results" below, to partially mitigate the impact of decreases in crude oil prices.
Net cash used in investing activities. For the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013, our net cash used in investing activities decreased by $836.7 million. This decrease was primarily attributed to the July 2013 Acquisition of oil and gas properties of $759.0 million. Additionally, for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013, our capital expenditures decreased by $75.8 million related to drilling and completions activities. This decrease is primarily due to fewer well completions caused by a temporary reduction in drilling rigs for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013.
Net cash provided by financing activities. For the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013, our net cash provided by financing activities decreased by $906.2 million. This decrease was primarily the result of the $734.9 million in net proceeds received from our 2021 Notes and the 2022 Notes offerings during the nine months ended September 30, 2013. All of the net proceeds from the 2021 Notes and the 2022 Notes issued in the nine months ended September 30, 2013 were used to repay borrowings on our credit facility. Additionally, for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013, our net borrowings under our credit facility decreased by $181.0 million.
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Our Properties
Williston Basin (171,000 net acres)
Our Williston Basin acreage is located primarily in Mountrail, Dunn, McKenzie and Williams counties of North Dakota. Our primary geologic target is the Bakken Pool where our primary objective is the Middle Bakken, a dolomitic, sandy interval between the two Bakken shales at an approximate vertical depth of 10,300-11,300 feet, and the Three Forks that is present 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.
The majority of our operations are in an area that we believe has higher reservoir pressure and a high degree of thermal maturity, which is prospective for both the Middle Bakken and multiple benches within the Three Forks. Based on recent drilling results, along with internal and third party reserve engineering analysis, we expect wells in this area to have estimated ultimate recoveries (“EURs”) that range from 450 MBOE to over 1,000 MBOE.
Our Leasehold
As of September 30, 2014, we had several hundred lease agreements representing approximately 334,000 gross and 180,000 net acres primarily in the Williston and Green River Basins. The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases:
Undeveloped Acreage (1) | Developed Acreage (2) | Total Acreage | ||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||
Williston Basin | ||||||||||||||||||
North Dakota | 98,939 | 53,059 | 207,834 | 117,668 | 306,773 | 170,727 | ||||||||||||
Green River Basin | ||||||||||||||||||
Wyoming | 12,643 | 3,580 | 8,035 | 1,585 | 20,678 | 5,165 | ||||||||||||
Colorado | 5,445 | 3,067 | 1,252 | 1,252 | 6,697 | 4,319 | ||||||||||||
Acreage Totals | 117,027 | 59,706 | 217,121 | 120,505 | 334,148 | 180,211 | ||||||||||||
(1) | Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage includes proved reserves. |
(2) | Developed acreage is the number of acres that are allocated or assignable to producing wells or wells capable of production. |
We believe we have satisfactory title, in all material respects, to substantially all of our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Substantially all of our proved oil and natural gas properties are pledged as collateral for borrowings under our credit facility.
Substantially all of the leases summarized in the preceding table will expire at the end of their respective primary terms unless (i) 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; (ii) the existing lease is renewed; or (iii) it is contained within a federal unit. Based on our current drilling plans, we do not expect to lose any material acreage through expiration. 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, 2014 | 1,631 | 1,334 | ||||
December 31, 2015 | 8,840 | 6,746 | ||||
December 31, 2016 | 2,596 | 1,579 | ||||
December 31, 2017 | 5,110 | 4,856 | ||||
Total | 18,177 | 14,515 | ||||
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Operating Results
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, 2013, this field contained 99.9% of our total proved reserves. Our revenues are directly affected by oil and natural gas prices, which can fluctuate dramatically. The commodity prices are largely beyond our control and are difficult to predict. We have seen significant volatility in oil and natural gas prices in recent years. The following table discloses our oil and gas sales volumes for the periods indicated:
For the Three Months Ended September 30, | For the Nine Months Ended September 30, | |||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||
Sales Volume: | ||||||||||||
Oil (MBbl) | 3,191 | 2,921 | 8,898 | 6,475 | ||||||||
Gas (MMcf) | 3,201 | 2,018 | 8,228 | 5,079 | ||||||||
Sales volumes (MBOE) (1) | 3,725 | 3,257 | 10,270 | 7,322 | ||||||||
Average Daily Sales Volumes: | ||||||||||||
Oil (MBbls/day) | 34.7 | 31.8 | 32.6 | 23.7 | ||||||||
Gas (MMcf/day) | 34.8 | 21.9 | 30.1 | 18.6 | ||||||||
Sales volumes (MBOE/day) (1) | 40.5 | 35.4 | 37.6 | 26.8 | ||||||||
(1) | We convert Mcf of gas equivalent to oil at a ratio of six Mcf of gas (including gas liquids) to one Bbl of oil. |
Sales prices received, and costs incurred, presented on a per BOE basis, for the three and nine months ended September 30, 2014 and 2013 are summarized in the following table:
For the Three Months Ended September 30, | For the Nine Months Ended September 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Sales Price: | ||||||||||||||||
Oil ($/Bbls) | $ | 85.35 | $ | 98.19 | $ | 88.50 | $ | 93.59 | ||||||||
Gas ($/Mcf) (1) | $ | 6.18 | $ | 6.32 | $ | 7.50 | $ | 6.31 | ||||||||
BOE ($/BOE) | $ | 78.44 | $ | 91.97 | $ | 82.69 | $ | 87.15 | ||||||||
Commodity Price Risk Management Activities ($/Sales BOE): | ||||||||||||||||
Settlements on commodity derivative instruments | $ | (2.42 | ) | $ | (5.73 | ) | $ | (4.25 | ) | $ | (2.11 | ) | ||||
Production Costs ($/Sales BOE): | ||||||||||||||||
Lease operating expenses | $ | 10.50 | $ | 6.28 | $ | 9.17 | $ | 6.46 | ||||||||
Production taxes | $ | 8.36 | $ | 10.00 | $ | 8.78 | $ | 9.40 | ||||||||
Gathering, transportation, marketing | $ | 2.40 | $ | 1.87 | $ | 2.34 | $ | 2.25 | ||||||||
DD&A | $ | 27.62 | $ | 29.81 | $ | 28.39 | $ | 29.62 | ||||||||
G&A | $ | 5.06 | $ | 3.86 | $ | 4.44 | $ | 4.53 | ||||||||
Stock‑based compensation | $ | 1.29 | $ | 1.19 | $ | 1.46 | $ | 1.52 | ||||||||
(1) | Average gas price received at the wellhead includes proceeds from natural gas liquids under percentage of proceeds contracts. |
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Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013
Oil sales revenues. Oil sales revenues decreased by $14.5 million to $272.4 million for the three months ended September 30, 2014 as compared to oil sales of $286.8 million for the same period in 2013. Our oil sales volume increased 9% to 3,191 thousand barrels (“MBbls”) in the third quarter of 2014 as compared to 2,921 MBbls in the third quarter of 2013. In the third quarter of 2014, our crude oil sales averaged 34.7 MBbls per day. The average price we realized on the sale of our oil decreased 13% from $98.19 per barrel sold in the third quarter of 2013 to $85.35 per barrel sold in the third quarter of 2014.
Natural gas sales revenues. Natural gas revenues increased by $7.0 million to $19.8 million for the three months ended September 30, 2014 as compared to natural gas revenues of $12.8 million for the same period in 2013. Natural gas sales volumes increased by 59% to 3,201 million cubic feet ("MMcf") for the three months ended September 30, 2014 as compared to 2,018 MMcf in the third quarter of 2013. In the third quarter of 2014, our natural gas sales averaged 34.8 MMcf per day. The volume increase is due to our continuing efforts to capture the natural gas from our wells through additional gas pipeline connection. The average price we realized on the sale of our natural gas was $6.18 per Mcf in the third quarter of 2014 compared to $6.32 per Mcf in the third quarter of 2013.
Oil and gas production expense. Our oil and gas production expense increased by $20.1 million to $79.2 million for the three months ended September 30, 2014, from $59.1 million for the three months ended September 30, 2013. The increase is comprised of a $1.4 million decrease in production taxes, a $18.7 million increase in lease operating expenses (“LOE”), and a $2.8 million increase in gathering, transportation and marketing expenses ("GTM").
The production tax decrease is attributable to decreased revenue as it is calculated as a fixed percentage of sales revenue. Production taxes as a percentage of sales revenue was 10.7% for the three months ended September 30, 2014 as compared to 10.9% for the three months ended September 30, 2013.
On a per unit basis, LOE increased from $6.28 per barrel sold in the third quarter of 2013 to $10.50 per barrel sold in the third quarter of 2014. The increase in LOE per barrel is partially a result of the normal decline in production, as our portfolio of producing wells ages, without a corresponding decrease in the ongoing fixed costs to operate these wells. Our LOE during the third quarter was also impacted by an increase in oil field service costs, particularly with respect to workover operations, and costs associated with winterization. As our well spacing declines, our LOE per barrel will also be negatively impacted by frac protection work, due to the need to shut in wells to avoid damage caused by completion work on adjacent wells. As a result of these protective measures, we temporarily reduce production from shut-in wells and then incur additional costs to bring the wells back onto production. As a result of these factors, LOE fluctuates between quarters as a result of the timing of expenses and realization of the corresponding production.
On a per unit basis, GTM increased from $1.87 per barrel sold in the third quarter of 2013 to $2.40 per barrel sold in the third quarter of 2014. GTM on a per BOE basis will vary depending on the transportation used and the rates charged by the carrier and natural gas sales volumes as a percentage of total sales volumes.
Depletion, depreciation, amortization and abandonment liability accretion (“DD&A”) expense. Our DD&A increased $5.8 million to $102.9 million for the three months ended September 30, 2014, from $97.1 million for the three months ended September 30, 2013. This increase is due to more production volumes being sold in the third quarter of 2014 as sales volumes increased by approximately 467 MBOE. On a per unit basis, DD&A decreased from $29.81 per BOE in the third quarter of 2013 to $27.62 per BOE in the third quarter of 2014. This decrease in DD&A rate was primarily the result of infill drilling and the addition of the related reserves.
General and administrative (“G&A”) expense. G&A expense increased by $6.3 million to $18.8 million for the three months ended September 30, 2014, from $12.6 million for the same period in 2013. Total employees have increased to 208 at September 30, 2014, from 172 at September 30, 2013. On a per unit basis, G&A increased from $3.86 per barrel sold in the third quarter of 2013 to $5.06 per barrel sold in the third quarter of 2014. The increase is primarily due to costs associated with the Arrangement Agreement with Whiting. Total transaction costs related to the Arrangement Agreement were approximately $6.8 million for the three months ended September 30, 2014. Excluding the transaction costs, G&A per barrel sold would have been $3.23 for the three months ended September 30, 2014.
Operating income. Our operating income was approximately $91.2 million for the three months ended September 30, 2014 as compared to approximately $130.8 million for the three months ended September 30, 2013. This 30%
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decrease in operating income is primarily attributed to lower crude oil pricing, higher production expenses, higher total depletion expense and merger costs which were offset by an increase in sales volumes.
Gain (loss) on commodity price risk management activities. Primarily due to the decrease in NYMEX crude oil futures prices at September 30, 2014 as compared to June 30, 2014, we incurred a net gain on our price risk management activities of $83.1 million for the three months ended September 30, 2014 as compared to a net loss of $60.1 million for the three months ended September 30, 2013. This change is a result of our hedging program used to mitigate our exposure to commodity price fluctuations. Included in the net gain on our commodity price risk management activities were cash settlements we incurred on our commodity derivative instruments of approximately $9.0 million for transactions that were settled during the third quarter of 2014. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time.
Interest income (expense), net. For the three months ended September 30, 2014, we recognized interest expense of approximately $26.9 million as compared to $21.0 million for the three months ended September 30, 2013.
We incurred interest expense for the three months ended September 30, 2014 and 2013 of approximately $32.7 million and $29.5 million, respectively, related to the credit facility and our Senior Notes. Included in interest expense for the three months ended September 30, 2014 and 2013 was the amortization of deferred financing costs and bond premium of $1.4 million and $1.2 million, respectively. For the three months ended September 30, 2014 and 2013, we capitalized interest costs of $7.2 million and $9.7 million, respectively.
Income tax expense. For the three months ended September 30, 2014, we recognized income tax expense of approximately $55.3 million as compared to $19.5 million for the three months ended September 30, 2013. The effective income tax rate for the three months ended September 30, 2014 was 37.5% as compared to 38.5% for the same period in 2013. The effective income tax rate differed for the three months ended September 30, 2014 and 2013 primarily due to state income taxes, estimated permanent differences and changes in the valuation allowance.
Net income. Our net income was approximately $92.2 million for the three months ended September 30, 2014 as compared to $31.2 million for the three months ended September 30, 2013. Our net income was positively impacted by an increase in price risk management activities of $143.2 million. However, offsetting this increase was the increase in income tax expense of $35.8 million, an increase in interest expense of $5.8 million and a decrease in operating income of $39.6 million.
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Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013
Oil sales revenues. Oil sales revenues increased by $181.5 million to $787.5 million for the nine months ended September 30, 2014 as compared to oil sales of $606.0 million for the same period in 2013. Our oil sales volume increased 37% to 8,898 MBbls in the first nine months of 2014 as compared to 6,475 MBbls in the first nine months of 2013. In the first nine months of 2014, our crude oil sales averaged 32.6 MBbls per day. The volume increase is due to the development of our Bakken properties as well as the acquisition in July 2013. Of the 2,423 MBbls increase in oil sales volume, 1,005 MBbls is related to the increase in production from producing wells acquired in the July 2013 acquisition and 1,418 MBbls is attributed to our ongoing development of our properties and undeveloped acreage prior to this acquisition. The average price we realized on the sale of our oil decreased 5% from $93.59 per barrel sold in the first nine months of 2013 to $88.50 per barrel sold in the first nine months of 2014.
Natural gas sales revenues. Natural gas revenues increased by $29.6 million to $61.7 million for the nine months ended September 30, 2014 as compared to natural gas revenues of $32.1 million for the same period in 2013. Natural gas sales volumes increased by 62% to 8,228 MMcf for the nine months ended September 30, 2014 as compared to 5,079 MMcf in the first nine months of 2013. In the first nine months of 2014, our natural gas sales averaged 30.1 MMcf per day. The average price we realized on the sale of our natural gas was $7.50 per Mcf in the first nine months of 2014 compared to $6.31 per Mcf in the first nine months of 2013. Overall, 79.6% of the increase in natural gas sales revenue was attributed to increased sales volumes and 20.4% was attributed to the increase in natural gas prices received. The volume increase is due to our continuing efforts to capture the natural gas from our wells through additional gas pipeline connections. Of the 3,148 MMcf increase in natural gas sales volume, 463 MMcf is related to the increase in production from producing wells acquired in the July 2013 acquisition and 2,685 MMcf is attributed to our ongoing development of our properties and undeveloped acreage prior to this acquisition.
Oil and gas production expense. Our oil and gas production expense increased by $75.7 million to $208.4 million for the nine months ended September 30, 2014, from $132.7 million for the nine months ended September 30, 2013. The increase is due to a $21.3 million increase in production taxes, a $46.9 million increase in LOE, and a $7.5 million increase in GTM.
The production tax increase is attributable to increased revenue as it is calculated as a fixed percentage of sales revenue. Production taxes as a percentage of sales revenue was 10.6% for the nine months ended September 30, 2014 as compared to 10.8% for the first nine months of 2013.
On a per unit basis, LOE increased from $6.46 per barrel sold in the first nine months of 2013 to $9.17 per barrel sold in the first nine months of 2014. The increase in LOE per barrel is partially a result of the normal decline in production, as our portfolio of producing wells ages, without a corresponding decrease in the ongoing fixed costs to operate these wells. Our LOE during the third quarter was also impacted by an increase in oil field service costs, particularly with respect to workover operations, and costs associated with winterization. As our well spacing declines, our LOE per barrel will also be negatively impacted by frac protection work, due to the need to shut in wells to avoid damage caused by completion work on adjacent wells. As a result of these protective measures, we temporarily reduce production from shut-in wells and then incur additional costs to bring the wells back onto production. As a result of these factors, LOE fluctuates between quarters as a result of the timing of expenses and realization of the corresponding production.
On a per unit basis, GTM increased from $2.25 per barrel sold in the first nine months of 2013 to $2.34 per barrel sold in the first nine months of 2014. GTM on a per BOE basis will vary depending on the transportation used and the rates charged by the carrier and natural gas sales volumes as a percentage of total sales volumes.
Depletion, depreciation, amortization and abandonment liability accretion expense. Our DD&A increased $74.7 million to $291.6 million for the nine months ended September 30, 2014, from $216.9 million for the nine months ended September 30, 2013. This increase is due to more production volumes being sold in the first nine months of 2014 as sales increased by approximately 2,948 MBOE. On a per unit basis, DD&A decreased from $29.62 per BOE in the first nine months of 2013 to $28.39 per BOE in the first nine months of 2014. This decrease in DD&A rate was primarily the result of infill drilling and the addition of the related reserves.
General and administrative expense. G&A expense increased by $12.4 million to $45.6 million for the nine months ended September 30, 2014, from $33.2 million for the same period in 2013. This increase is partially due to costs associated with the Arrangement Agreement with Whiting. Total transaction costs related to the Arrangement Agreement
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were approximately $6.8 million for the nine months ended September 30, 2014. Total employees have increased to 208 at September 30, 2014, from 172 at September 30, 2013. On a per unit basis, G&A decreased from $4.53 per barrel sold in the first nine months of 2013 to $4.44 per barrel sold in the first nine months of 2014. Excluding the transaction costs, G&A per barrel sold would have decreased to $3.77 for the first nine months ended September 30, 2014. The net decrease per barrel sold is primarily due to our increase in sales volumes from our ongoing Bakken development program as well as the acquisition in July 2013.
Operating income. Our operating income was approximately $303.7 million for the nine months ended September 30, 2014 as compared to approximately $255.4 million for the nine months ended September 30, 2013. This 19% increase in operating income is attributed to our on-going successful completions of wells and resulting increase in sales volumes in our Bakken play, and to a lesser extent, our acquisition in July 2013.
Gain (loss) on commodity price risk management activities. Primarily due to the decrease in NYMEX crude oil futures prices at September 30, 2014 as compared to December 31, 2013, we incurred a net gain on our price risk management activities of $2.0 million for the nine months ended September 30, 2014 as compared to a net loss of $53.2 million for the nine months ended September 30, 2013. This change is a result of our hedging program used to mitigate our exposure to commodity price fluctuations. Included in the net gain on our commodity price risk management activities were cash settlements we incurred on our commodity derivative instruments of approximately $43.6 million for transactions that were settled during the first nine months of 2014. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled and we will likely add to our hedging program. Therefore, we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time.
Interest income (expense), net. For the nine months ended September 30, 2014, we recognized interest expense of approximately $77.0 million as compared to $50.6 million for the nine months ended September 30, 2013.
We incurred interest expense for the nine months ended September 30, 2014 and 2013 of approximately $96.1 million and $73.3 million, respectively, related to the credit facility and our Senior Notes. Year-to-date 2014 includes interest expense from the issuance of our $400 million 2022 Notes issued in July 2013. Included in interest expense for the nine months ended September 30, 2014 and 2013 was the amortization of deferred financing costs and bond premium of $4.2 million and $3.0 million, respectively. For the nine months ended September 30, 2014 and 2013, we capitalized interest costs of $23.2 million and $25.6 million, respectively.
Income tax expense. For the nine months ended September 30, 2014, we recognized income tax expense of approximately $86.3 million as compared to $58.4 million for the nine months ended September 30, 2013. The effective income tax rate for the nine months ended September 30, 2014 was 37.7% as compared to 38.1% for the same period in 2013. The effective income tax rate differed for the nine months ended September 30, 2014 and 2013 primarily due to state income taxes, estimated permanent differences and changes in the valuation allowance.
Net income. Our net income was approximately $142.5 million for the nine months ended September 30, 2014 as compared to $94.8 million for the nine months ended September 30, 2013. Our overall increase in net income of $47.6 million for nine months ended September 30, 2014 as compared to the same period in 2013 was primarily the result of a benefit in our commodity price risk management activities of $55.2 million, offset by an increase in income tax expense of $27.9 million, and an increase in interest expense of $26.3 million. Additionally, our net income was positively impacted by an increase in operating income of $48.3 million.
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Commitments and Contingencies
For a discussion of our commitments and contingencies, please refer to Note 11 - Commitments and Contingencies under Item 1 in this Quarterly Report, which is incorporated herein by reference.
Off Balance Sheet Arrangements
The Company did not have any off balance sheet arrangements, as such term is defined in Item 303(a)(4)(ii) of Regulation S-K, at September 30, 2014 and December 31, 2013.
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Certain of the Company’s accounting policies are considered critical, as these policies are the most important to the depiction of the Company’s financial statements and require significant, difficult, or complex judgments, often employing the use of estimates about the effects of matters that are inherently uncertain. A summary of the Company’s significant accounting policies is included in Note 2 - Basis of Presentation and Significant Accounting Policies to the Company’s consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2013, as well as in the Management’s Discussion and Analysis of Financial Condition and Results of Operations section in such Form 10-K. There have been no significant changes in the Company’s application of its critical accounting policies during the nine months ended 2014.
Recently Issued Accounting Pronouncements
For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, refer to the section titled Recent Accounting Pronouncements under Note 2 - Basis of Presentation and Significant Accounting Policies under Item 1 of this Quarterly Report.
Effects of Pricing and Inflation
The demand for most oilfield products and services has increased in the Williston Basin beginning in 2010 and continuing through 2014. Typically, as prices for oil and natural gas increase, so do the associated costs. As oil and natural gas prices decline, we would expect associated costs to decline, however, there may be a lag or the changes may be disproportionate to the lower prices. Material changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, depletion expense, impairment assessments of oil and gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk
Our primary market risk is market changes in oil and natural gas prices. The market prices for oil and natural gas have been highly volatile and are likely to continue to be highly volatile in the future, which will impact our prospective revenues from the sale of products or properties. Currently, we utilize swaps and “no premium” collars to reduce the effect of price changes on a portion of our future oil production. We do not enter into derivative instruments for trading purposes. All commodity derivative instruments are accounted for using mark-to-market accounting.
We use no premium collars to establish floor and ceiling prices on our anticipated future oil production. We neither receive nor pay net premiums when we enter into these arrangements. These contracts are settled monthly. When the settlement price (the market price for oil or natural gas on the settlement date) for a period is above the ceiling price, we pay our counterparty. When the settlement price for a period is below the floor price, our counterparty is required to pay us.
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We use swaps to fix the sales price for our anticipated future oil production. Upon settlement, we receive a fixed price for the underlying commodity and pay our counterparty a floating market price, as defined in each instrument. These instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, we pay our counterparty. When the fixed price exceeds the floating price, our counterparty is required to make a payment to us.
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. Our wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc., is currently a party to derivative contracts with eleven counterparties, and the Company is a guarantor of Kodiak Oil & Gas (USA) Inc. We have netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparties in the event of contract termination. Although the instruments are valued using indices published by established exchanges, the instruments are traded directly with the counterparties. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.
The objective of our use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, these instruments may also limit our ability to benefit from favorable price movements. We 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 our existing positions.
The Company’s commodity derivative contracts as of September 30, 2014 are summarized below:
Collars | Basis (1) | Quantity (Bbl/d) | Strike Price ($/Bbl) | |||
Oct 1, 2014 - Dec 31, 2015 | NYMEX | 300 - 350 | $85.00 - $102.75 | |||
Swaps | Basis (1) | Average Quantity (Bbl/d) | Average Swap Price ($/Bbl) | |||
Oct 1, 2014 - Dec 31, 2014 Total | NYMEX | 25,800 | $93.41 | |||
Jan 1, 2015 - Jun 30, 2015 Total | NYMEX | 7,796 | $93.08 | |||
Jul 1, 2015 - Dec 31, 2015 Total | NYMEX | 3,291 | $91.17 | |||
(1) | NYMEX refers to quoted prices on the New York Mercantile Exchange |
We determine the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and our own credit rating. We also perform an internal valuation to ensure the reasonableness of third‑party quotes. In consideration of counterparty credit risk, we assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, we consider that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. For further details regarding our derivative contracts please refer to Note 6 - Commodity Derivative Instruments under Item 1 in this Quarterly Report.
Interest Rate Risk
At September 30, 2014, we had $800.0 million outstanding under our 2019 Notes due December 1, 2019 at a fixed interest rate of 8.125%, $350.0 million outstanding under our 2021 Notes due January 15, 2021 at a fixed interest rate of 5.50% and $400.0 million outstanding under our 2022 Notes due February 1, 2022 at a fixed interest rate of 5.50%.
In addition, as of September 30, 2014, we had $1.35 billion available to us under our credit facility, of which, $870.0 million was drawn at September 30, 2014. The credit facility bears interest at variable rates. Assuming we had the maximum amount outstanding at September 30, 2014 under our credit facility of $1.35 billion, a 1.0% increase in interest rates would result in additional annualized interest expense of $13.5 million.
For a detailed discussion of the foregoing credit arrangements, including a discussion of the applicable interest rates, please refer to Note 4 - Long-Term Debt under Item 1 in this Quarterly Report.
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ITEM 4. CONTROLS AND PROCEDURES
Management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of September 30, 2014. On the basis of this review, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
There have not been any changes in the Company's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated by the SEC under the Exchange Act) during the Company's most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect the Company's internal control over financial reporting.
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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Subsequent to the announcement of the Arrangement, seven purported class action lawsuits have been filed on behalf of the Company's shareholders in the United States District Court for the District of Colorado: Quigley and Koelling v.Whiting Petroleum Corporation, et al., Case No. 1:14-cv-02023, filed July 22, 2014 (the plaintiffs voluntarily dismissed this lawsuit on September 24, 2014); Fioravanti v. Krysiak, et al., Case No. 1:14-cv-02037, filed July 23, 2014 (the plaintiffs voluntarily dismissed this lawsuit October 24, 2014); Wilkinson v.Whiting Petroleum Corporation, et al., Case No. 1:14-cv-2074, filed July 25, 2014 (the plaintiffs voluntarily dismissed this lawsuit on October 23, 2014); Goldsmith v. Krysiak, et al., Case No. 1:14-cv-2098, filed July 29, 2014 (the plaintiffs voluntarily dismissed this lawsuit on October 31, 2014); Rogowski v.Whiting Petroleum Corporation, et al., Case No. 1:14-cv-2136, filed July 31, 2014 (the plaintiffs voluntarily dismissed this lawsuit on October 20, 2014); Reiter v. Peterson, et al., Case No. 1:14-cv-02176, filed August 6, 2014; Sohler v. Whiting Petroleum Corporation, et al., Case No. 1:14-cv-02863, filed October 20, 2014 (the “Sohler Case”); and one purported class action lawsuit has been filed on behalf of the Company's shareholders in Denver District Court, State of Colorado: The Booth Family Trust v. Kodiak Oil & Gas Corp., et al., Case No. 14-cv-32947, filed July 25, 2014. This last case was removed to the United States District Court for the District of Colorado on September 4, 2014 and is pending in that court now as Case No. 1:14-cv-2457. It is possible that other related or amended suits could subsequently be filed. The defendants have filed motions to dismiss with prejudice in the all remaining cases other than the Sohler Case. The allegations in the three remaining lawsuits are similar. They purport to be brought as class actions on behalf of all shareholders of the Company. The complaints name as defendants the individual members of the Company's board of directors, Whiting and Whiting Canadian Sub and list the Company as a nominal party or a defendant. The complaints allege that the Company's board of directors breached its fiduciary duties to the Company's shareholders by, among other things, failing to engage in a fair sale process before approving the Arrangement and to maximize shareholder value in connection with the Arrangement. Additionally, the Sohler Case alleges violations under Sections 14(a) and 20(a) of the Exchange Act and SEC Rule 14a-9 promulgated thereunder. Specifically, the complaints allege that the Company's board of directors undervalued the Company in connection with the Arrangement and that the Company's board of directors agreed to certain deal protection mechanisms that precluded the Company from obtaining competing offers. The complaints also allege that Whiting and Whiting Canadian Sub aided and abetted the Company's board of directors’ alleged breaches of fiduciary duties. The Sohler Case alleges additionally that in issuing the preliminary joint proxy statement/circular the Company's board of directors violated the cited sections of and rule promulgated under the Exchange Act. The complaints seek, among other things, injunctive relief preventing the closing of the Arrangement, rescission of the Arrangement or an award of rescissory damages to the purported class in the event that the Arrangement is consummated, and damages, including counsel fees and expenses. Whiting and the Company believe each lawsuit is without merit.
ITEM 1A. RISK FACTORS
Other than as set forth below, there have been no material changes to the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2013, as filed with the SEC on February 27, 2014. The risk factors in our Annual Report on Form 10-K for the year ended December 31, 2013, in addition to the other information set forth in this quarterly report, could materially affect our business, financial condition or results of operations. Additional risks and uncertainties not currently known to us or that we deem to be immaterial could also materially adversely affect our business, financial condition or results of operations.
Our business could be negatively impacted by security threats, including cybersecurity threats and other disruptions.
As a crude oil and natural gas producer, we face various security threats, including security threats to our remote well locations and cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable. Cybersecurity attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, corruption of data and financial losses. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to interruptions of production or distribution, damage to our wells
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and other equipment or property, losses of sensitive information, or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.
Failure to complete the Arrangement could negatively affect our share price, future business and financial results.
Completion of the Arrangement is not assured and is subject to risks, including the risks that approval of the transaction by our shareholders and the stockholders of Whiting, by the applicable court or by governmental agencies will not be obtained or that certain other closing conditions will not be satisfied. If the Arrangement is not completed, our ongoing business and financial results may be adversely affected and we will be subject to several risks, including:
• | having to pay certain significant transaction costs relating to the Arrangement without receiving the benefits of the Arrangement; |
• | potentially having to reimburse up to $10.0 million of Whiting’s expenses if our shareholder approval is not obtained or a termination fee of $130.0 million plus reimbursement of up to $10.0 million of Whiting’s expenses in other specific circumstances, including without limitation, a change in our board of directors' recommendation to our shareholders or termination to accept an alternative acquisition proposal; |
• | our share price may decline to the extent that the current market prices reflect an assumption by the market that the Arrangement will be completed; and |
• | we may be subject to litigation related to any failure to complete the Arrangement. |
We will incur substantial transaction fees and costs in connection with the Arrangement.
We expect to incur a significant amount of non-recurring expenses in connection with the Arrangement. Additional unanticipated costs may be incurred in the course of the integration of our business and the business of Whiting. We cannot be certain that the elimination of duplicative costs or the realization of other efficiencies related to the integration of the two businesses will offset the transaction and integration costs in the near term, or at all.
We and Whiting may be unable to obtain the court and regulatory approvals required to complete the Arrangement or, in order to do so, we and Whiting may be required to comply with material restrictions or conditions that may negatively affect the combined company after the Arrangement is completed or cause us to abandon the Arrangement. Failure to complete the Arrangement could negatively affect our future business and financial results.
Completion of the Arrangement is contingent upon, among other things, the receipt of certain court and regulatory approvals. We and Whiting can provide no assurance that all required court and regulatory approvals will be obtained or that the approvals or consents will not contain terms, conditions or restrictions that would be detrimental to the combined company after completion of the Arrangement.
Delays in completing the Arrangement may substantially reduce the expected benefits of the Arrangement.
Satisfying the conditions to, and completion of, the Arrangement may take longer than, and could cost more than, we expect. Any delay in completing or any additional conditions imposed in order to complete the Arrangement may materially adversely affect the synergies and other benefits that we expect to achieve from the Arrangement and the integration of our businesses. In addition, we and Whiting each have the right to terminate the Arrangement Agreement if the Arrangement is not completed by January 9, 2015.
Shareholder litigation against us and/or Whiting could result in an injunction preventing completion of the Arrangement, the payment of damages in the event the Arrangement is completed and/or may adversely affect the combined company’s business, financial condition or results of operations following the Arrangement.
Transactions such as the Arrangement are often subject to lawsuits by stockholders. In connection with the Arrangement, seven purported class action lawsuits have been filed on behalf of the Company's shareholders in the United States District Court for the District of Colorado: Quigley and Koelling v.Whiting Petroleum Corporation, et al., Case No. 1:14-cv-02023, filed July 22, 2014 (the plaintiffs voluntarily dismissed this lawsuit on September 24, 2014); Fioravanti v.
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Krysiak, et al., Case No. 1:14-cv-02037, filed July 23, 2014 (the plaintiffs voluntarily dismissed this lawsuit October 24, 2014); Wilkinson v.Whiting Petroleum Corporation, et al., Case No. 1:14-cv-2074, filed July 25, 2014 (the plaintiffs voluntarily dismissed this lawsuit on October 23, 2014); Goldsmith v. Krysiak, et al., Case No. 1:14-cv-2098, filed July 29, 2014 (the plaintiffs voluntarily dismissed this lawsuit on October 31, 2014); Rogowski v.Whiting Petroleum Corporation, et al., Case No. 1:14-cv-2136, filed July 31, 2014 (the plaintiffs voluntarily dismissed this lawsuit on October 20, 2014); Reiter v. Peterson, et al., Case No. 1:14-cv-02176, filed August 6, 2014; Sohler v. Whiting Petroleum Corporation, et al., Case No. 1:14-cv-02863, filed October 20, 2014 (the “Sohler Case”); and one purported class action lawsuit has been filed on behalf of the Company's shareholders in Denver District Court, State of Colorado: The Booth Family Trust v. Kodiak Oil & Gas Corp., et al., Case No. 14-cv-32947, filed July 25, 2014. This last case was removed to the United States District Court for the District of Colorado on September 4, 2014 and is pending in that court now as Case No. 1:14-cv-2457. It is possible that other related or amended suits could subsequently be filed. The defendants have filed motions to dismiss with prejudice in the all remaining cases other than the Sohler Case. The allegations in the three remaining lawsuits are similar. They purport to be brought as class actions on behalf of all shareholders of the Company. The complaints name as defendants the individual members of the Company's board of directors, Whiting and Whiting Canadian Sub and list the Company as a nominal party or a defendant. The complaints allege that the Company's board of directors breached its fiduciary duties to the Company's shareholders by, among other things, failing to engage in a fair sale process before approving the Arrangement and to maximize shareholder value in connection with the Arrangement. Additionally, the Sohler Case alleges violations under Sections 14(a) and 20(a) of the Exchange Act and SEC Rule 14a-9 promulgated thereunder. Specifically, the complaints allege that the Company's board of directors undervalued the Company in connection with the Arrangement and that the Company's board of directors agreed to certain deal protection mechanisms that precluded the Company from obtaining competing offers. The complaints also allege that Whiting and Whiting Canadian Sub aided and abetted the Company's board of directors’ alleged breaches of fiduciary duties. The Sohler Case alleges additionally that in issuing the preliminary joint proxy statement/circular the Company's board of directors violated the cited sections of and rule promulgated under the Exchange Act. The complaints seek, among other things, injunctive relief preventing the closing of the Arrangement, rescission of the Arrangement or an award of rescissory damages to the purported class in the event that the Arrangement is consummated, and damages, including counsel fees and expenses. Whiting and the Company believe each lawsuit is without merit.
One of the conditions to the closing of the Arrangement is that no law, order, injunction or judgment has been enacted or issued by any government entity that has the effect of prohibiting the consummation of the Arrangement. Consequently, if any lawsuit is successful in obtaining an injunction prohibiting us or Whiting from consummating the Arrangement on the agreed upon terms, the injunction may prevent the Arrangement from being completed within the expected timeframe, or at all. Furthermore, if the Arrangement is prevented or delayed, the lawsuits could result in substantial costs, including any costs associated with the indemnification of directors. The defense or settlement of any lawsuit or claim that remains unresolved at the time the Arrangement is completed may adversely affect the combined company’s business, financial condition or results of operations.
We will be subject to various uncertainties and contractual restrictions while the Arrangement is pending that could adversely affect our financial results.
Uncertainty about the effect of the Arrangement on employees, service providers, suppliers and customers may have an adverse effect on us. These uncertainties may impair our ability to attract, retain and motivate key personnel until the Arrangement is completed and for a period of time thereafter, and could cause service providers, customers, suppliers and others who deal with us to seek to change existing business relationships with us. Employee retention and recruitment may be particularly challenging prior to completion of the Arrangement, as employees and prospective employees may experience uncertainty about their future roles with the combined company.
The pursuit of the Arrangement and the preparation for the integration of the two companies may place a significant burden on management and internal resources. Any significant diversion of management’s attention away from ongoing business and any difficulties encountered in the transition and integration process could affect our financial results or the financial results of the combined company.
In addition, the Arrangement Agreement restricts us from taking certain specified actions while the Arrangement is pending without first obtaining Whiting’s prior written consent. These restrictions may limit us from pursuing attractive business opportunities and making other changes to our business prior to completion of the Arrangement or termination of the Arrangement Agreement.
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We and Whiting may experience difficulties in integrating our businesses, which could cause the combined company to fail to realize many of the anticipated potential benefits of the Arrangement.
We and Whiting entered into the Arrangement Agreement with the expectation that the Arrangement will result in various benefits, including, among other things, operating efficiencies and cost savings. Achieving the anticipated benefits of the Arrangement will depend in part upon whether our two companies integrate our businesses in an efficient and effective manner. Whiting and us may not be able to accomplish this integration process successfully. The difficulties of combining the two companies’ businesses potentially will include, among other things:
• | the necessity of addressing possible differences incorporating cultures and management philosophies, and the integration of certain operations following the transaction will require the dedication of significant management resources, which may temporarily distract management’s attention from the day-to-day business of the combined company; and |
• | any inability of our management to cause best practices to be applied to the combined company’s businesses. |
An inability to realize the full extent of the anticipated benefits of the transaction, as well as any delays encountered in the transition process, could have an adverse effect upon the revenues, level of expenses and operating results of the combined company, which may affect the value of the our common stock after the closing of the Arrangement.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
These disclosures are not applicable to us.
ITEM 5. OTHER INFORMATION
None.
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ITEM 6. EXHIBITS
Exhibit Number | Description | |
31.1 | Certification of the Chief Executive Officer required by Rule 13a-14(a) or Rule 15d-14(a) | |
31.2 | Certification of the Chief Financial Officer required by Rule 13a-14(a) or Rule 15d-14(a) | |
32.1 | Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350 | |
32.2 | Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350 | |
101 | The following materials are filed herewith: (i) XBRL Instance, (ii) XBRL Taxonomy Extension Schema, (iii) XBRL Taxonomy Extension Calculation, (iv) XBRL Taxonomy Extension Labels, (v) XBRL Taxonomy Extension Presentation, and (vi) XBRL Taxonomy Extension Definition. In accordance with Rule 406T of Regulation S-T, the information in these exhibits is furnished and deemed not filed or a part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Exchange Act of 1934, and otherwise is not subject to liability under these sections and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by the specific reference in such filing. | |
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
KODIAK OIL & GAS CORP. | ||
November 6, 2014 | By: | /s/ LYNN A. PETERSON |
Lynn A. Peterson | ||
President and Chief Executive Officer | ||
(principal executive officer) | ||
November 6, 2014 | By: | /s/ JAMES P. HENDERSON |
James P. Henderson | ||
Chief Financial Officer, Secretary and Treasurer | ||
(principal financial and accounting officer) | ||
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