XFRA:OS7 Oasis Petroleum Inc Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

 

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

For the quarterly period ended June 30, 2012

or

 

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

For the transition period from             to            

Commission file number: 1-34776

 

 

Oasis Petroleum Inc.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   80-0554627
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)

1001 Fannin Street, Suite 1500

Houston, Texas

  77002
(Address of principal executive offices)   (Zip Code)

(281) 404-9500

(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  ¨

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  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer   ¨  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

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

Number of shares of the registrant’s common stock outstanding at August 3, 2012: 93,342,852 shares.

 

 

 


Table of Contents

OASIS PETROLEUM INC.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2012

TABLE OF CONTENTS

 

     Page  

PART I — FINANCIAL INFORMATION

     1   

Item 1. — Financial Statements (Unaudited)

     1   

Condensed Consolidated Balance Sheet at June 30, 2012 and December 31, 2011

     1   

Condensed Consolidated Statement of Operations for the Three and Six Months Ended June  30, 2012 and 2011

     2   

Condensed Consolidated Statement of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2012

     3   

Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2012 and 2011

     4   

Notes to the Condensed Consolidated Financial Statements

     5   

Item  2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations

     19   

Item 3. — Quantitative and Qualitative Disclosures About Market Risk

     29   

Item 4. — Controls and Procedures

     30   

PART II — OTHER INFORMATION

     31   

Item 1. — Legal Proceedings

     31   

Item 1A. — Risk Factors

     31   

Item 2. — Unregistered Sales of Equity Securities and Use of Proceeds

     31   

Item 6. — Exhibits

     31   

SIGNATURES

     33   

EXHIBIT INDEX

     34   

 

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Table of Contents

PART I — FINANCIAL INFORMATION

Item 1. — Financial Statements (Unaudited)

Oasis Petroleum Inc.

Condensed Consolidated Balance Sheet

(Unaudited)

 

     June 30,
2012
    December 31,
2011
 
     (In thousands, except share data)  
ASSETS     

Current assets

    

Cash and cash equivalents

   $ 238,886      $ 470,872   

Short-term investments

     —          19,994   

Accounts receivable — oil and gas revenues

     79,478        52,164   

Accounts receivable — joint interest partners

     66,794        67,268   

Inventory

     19,550        3,543   

Prepaid expenses

     674        2,140   

Advances to joint interest partners

     1,957        3,935   

Derivative instruments

     35,257        —     

Deferred income taxes

     —          3,233   

Other current assets

     1        491   
  

 

 

   

 

 

 

Total current assets

     442,597        623,640   
  

 

 

   

 

 

 

Property, plant and equipment

    

Oil and gas properties (successful efforts method)

     1,769,570        1,235,357   

Other property and equipment

     41,333        20,859   

Less: accumulated depreciation, depletion, amortization and impairment

     (261,529     (176,261
  

 

 

   

 

 

 

Total property, plant and equipment, net

     1,549,374        1,079,955   
  

 

 

   

 

 

 

Derivative instruments

     18,167        4,362   

Deferred costs and other assets

     26,232        19,425   
  

 

 

   

 

 

 

Total assets

   $ 2,036,370      $ 1,727,382   
  

 

 

   

 

 

 
LIABILITIES AND STOCKHOLDERS’ EQUITY     

Current liabilities

    

Accounts payable

   $ 1,010      $ 12,207   

Advances from joint interest partners

     28,444        9,064   

Revenues and production taxes payable

     56,795        19,468   

Accrued liabilities

     237,694        119,692   

Accrued interest payable

     16,427        15,774   

Derivative instruments

     —          5,907   

Deferred income taxes

     11,780        —     

Other current liabilities

     2,895        472   
  

 

 

   

 

 

 

Total current liabilities

     355,045        182,584   
  

 

 

   

 

 

 

Long-term debt

     800,000        800,000   

Asset retirement obligations

     16,982        13,075   

Derivative instruments

     —          3,505   

Deferred income taxes

     133,178        92,983   

Other liabilities

     1,751        997   
  

 

 

   

 

 

 

Total liabilities

     1,306,956        1,093,144   
  

 

 

   

 

 

 

Commitments and contingencies (Note 11)

    

Stockholders’ equity

    

Common stock, $0.01 par value; 300,000,000 shares authorized; 93,185,023 issued and 93,122,353 outstanding at June 30, 2012; 92,483,393 issued and 92,460,914 outstanding at December 31, 2011

     922        921   

Treasury stock, at cost; 62,670 and 22,479 shares at June 30, 2012 and December 31, 2011, respectively

     (1,808     (602

Additional paid-in-capital

     651,271        647,374   

Retained earnings (deficit)

     79,029        (13,455
  

 

 

   

 

 

 

Total stockholders’ equity

     729,414        634,238   
  

 

 

   

 

 

 

Total liabilities and stockholders’ equity

   $ 2,036,370      $ 1,727,382   
  

 

 

   

 

 

 

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

 

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Table of Contents

Oasis Petroleum Inc.

Condensed Consolidated Statement of Operations

(Unaudited)

 

    Three Months Ended June 30,     Six Months Ended June 30,  
    2012     2011     2012     2011  
    (In thousands, except per share data)  

Revenues

       

Oil and gas revenues

  $ 145,203      $ 67,206      $ 283,109      $ 125,950   

Well services revenues

    3,861        —          4,521        —     
 

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    149,064        67,206        287,630        125,950   
 

 

 

   

 

 

   

 

 

   

 

 

 

Expenses

       

Lease operating expenses

    12,029        5,951        21,845        11,581   

Well services operating expenses

    1,207        —          1,684        —     

Marketing, transportation and gathering expenses

    1,970        247        4,539        559   

Production taxes

    13,720        7,085        26,986        13,168   

Depreciation, depletion and amortization

    44,213        13,100        83,099        26,912   

Exploration expenses

    —          259        2,835        291   

Impairment of oil and gas properties

    2,203        1,536        2,571        2,917   

General and administrative expenses

    13,537        6,614        25,736        12,564   
 

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

    88,879        34,792        169,295        67,992   
 

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    60,185        32,414        118,335        57,958   
 

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense)

       

Net gain (loss) on derivative instruments

    74,595        27,547        56,009        (4,119

Interest expense

    (14,074     (6,761     (27,973     (11,959

Other income

    776        379        1,374        691   
 

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

    61,297        21,165        29,410        (15,387
 

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

    121,482        53,579        147,745        42,571   

Income tax expense

    45,439        20,230        55,261        16,069   
 

 

 

   

 

 

   

 

 

   

 

 

 

Net income

  $ 76,043      $ 33,349      $ 92,484      $ 26,502   
 

 

 

   

 

 

   

 

 

   

 

 

 

Earnings per share:

       

Basic and diluted (Note 10)

  $ 0.82      $ 0.36      $ 1.00      $ 0.29   

Weighted average shares outstanding:

       

Basic (Note 10)

    92,176        92,048        92,153        92,047   

Diluted (Note 10)

    92,222        92,151        92,339        92,177   

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

 

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Table of Contents

Oasis Petroleum Inc.

Condensed Consolidated Statement of Changes in Stockholders’ Equity

(Unaudited)

(In thousands)

 

     Common Stock      Treasury Stock     Additional
Paid-in-Capital
    Retained
Earnings
(Deficit)
    Total
Stockholders’
Equity
 
   Shares     Amount      Shares      Amount        

Balance as of December 31, 2011

     92,461      $ 921         22       $ (602   $ 647,374      $ (13,455   $ 634,238   

Stock-based compensation

     702        —           —           —          3,898        —          3,898   

Vesting of restricted shares

     —          1         —           —          (1     —          —     

Treasury stock – tax withholdings

     (41     —           41         (1,206     —          —          (1,206

Net income

     —          —           —           —          —          92,484        92,484   
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance as of June 30, 2012

     93,122      $ 922         63       $ (1,808   $ 651,271      $ 79,029      $ 729,414   
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

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

 

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Table of Contents

Oasis Petroleum Inc.

Condensed Consolidated Statement of Cash Flows

(Unaudited)

 

     Six Months Ended June 30,  
     2012     2011  
     (In thousands)  

Cash flows from operating activities:

    

Net income

   $ 92,484      $ 26,502   

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

    

Depreciation, depletion and amortization

     83,099        26,912   

Impairment of oil and gas properties

     2,571        2,917   

Deferred income taxes

     55,161        16,069   

Derivative instruments

     (56,009     4,119   

Stock-based compensation expenses

     3,898        1,571   

Debt discount amortization and other

     1,265        648   

Working capital and other changes:

    

Change in accounts receivable

     (26,840     (19,945

Change in inventory

     (21,636     (65

Change in prepaid expenses

     1,500        (254

Change in other current assets

     490        (211

Change in other assets

     (7,365     (103

Change in accounts payable and accrued liabilities

     40,022        43,612   

Change in other current liabilities

     2,470        —     

Change in other liabilities

     750        323  
  

 

 

   

 

 

 

Net cash provided by operating activities

     171,860        102,095   
  

 

 

   

 

 

 

Cash flows from investing activities:

    

Capital expenditures

     (440,781     (212,267

Derivative settlements

     (2,465     (4,652

Purchases of short-term investments

     —          (164,913

Redemptions of short-term investments

     19,994        39,974  

Advances to joint interest partners

     1,978        983   

Advances from joint interest partners

     19,380        5,851   
  

 

 

   

 

 

 

Net cash used in investing activities

     (401,894     (335,024
  

 

 

   

 

 

 

Cash flows from financing activities:

    

Proceeds from issuance of senior notes

     —          400,000   

Purchases of treasury stock

     (1,206     (559

Debt issuance costs

     (746     (10,027
  

 

 

   

 

 

 

Net cash (used in) provided by financing activities

     (1,952     389,414   
  

 

 

   

 

 

 

(Decrease) increase in cash and cash equivalents

     (231,986     156,485   

Cash and cash equivalents:

    

Beginning of period

     470,872        143,520   
  

 

 

   

 

 

 

End of period

   $ 238,886      $ 300,005   
  

 

 

   

 

 

 

Supplemental non-cash transactions:

    

Change in accrued capital expenditures

   $ 104,486      $ (6,676

Change in asset retirement obligations

     4,185        2,357   

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

 

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Table of Contents

OASIS PETROLEUM INC.

Notes to Condensed Consolidated Financial Statements (Unaudited)

1. Organization and Operations of the Company

Organization

Oasis Petroleum Inc. (“Oasis” or the “Company”) was formed on February 25, 2010, pursuant to the laws of the State of Delaware, to become a holding company for Oasis Petroleum LLC (“OP LLC”), the Company’s predecessor, which was formed as a Delaware limited liability company on February 26, 2007. In connection with its initial public offering in June 2010 and related corporate reorganization, the Company acquired all of the outstanding membership interests in OP LLC in exchange for shares of the Company’s common stock. In May 2007, the Company formed Oasis Petroleum North America LLC (“OPNA”), a Delaware limited liability company, to conduct its domestic oil and natural gas exploration and production activities. In April 2008, the Company formed Oasis Petroleum International LLC (“OPI”), a Delaware limited liability company, to conduct business development activities outside of the United States of America. As of June 30, 2012, OPI had no business activities or material assets. In June 2011, the Company formed Oasis Well Services LLC (“OWS”), a Delaware limited liability company, to provide well services to OPNA. In July 2011, the Company formed Oasis Petroleum Marketing LLC (“OPM”), a Delaware limited liability company, to provide marketing services to OPNA.

Nature of Business

The Company is an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources in the Williston Basin. The Company’s proved and unproved oil and natural gas properties are located in the Montana and North Dakota areas of the Williston Basin and are owned by OPNA. The Company also operates businesses that are complementary to its primary development and production activities, including a marketing business (OPM) and a well services business (OWS).

2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying condensed consolidated financial statements of the Company include the accounts of Oasis and its wholly owned subsidiaries: OP LLC, OPNA, OPI, OWS and OPM. The accompanying condensed consolidated financial statements of the Company have not been audited by the Company’s independent registered public accounting firm, except that the condensed consolidated balance sheet at December 31, 2011 is derived from audited financial statements. All significant intercompany transactions have been eliminated in consolidation. Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications. These reclassifications have no impact on net income. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for the fair presentation have been included. In preparing the accompanying condensed consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

These interim financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements and should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Annual Report”).

Significant Accounting Policies

There have been no material changes to the Company’s critical accounting policies and estimates from those disclosed in the 2011 Annual Report.

3. Inventory

Equipment and materials consist primarily of tubular goods, well equipment to be used in future drilling or repair operations and well fracturing equipment, all of which are stated at the lower of cost or market with cost determined on an average cost method. Crude oil inventories include oil in tank and line fill and are valued at the lower of average cost or market value. Inventory consists of the following:

 

     June 30, 2012      December 31,
2011
 
     (In thousands)  

Equipment and materials

   $ 16,869       $ 2,709   

Crude oil inventory

     2,681         834   
  

 

 

    

 

 

 

Total inventory

   $ 19,550       $ 3,543   
  

 

 

    

 

 

 

 

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Table of Contents

4. Property, Plant and Equipment

The following table sets forth the Company’s property, plant and equipment:

 

     June 30, 2012     December 31, 2011  
     (In thousands)  

Proved oil and gas properties (1)

   $ 1,691,964      $ 1,152,532   

Less: Accumulated depreciation, depletion, amortization and impairment

     (257,607     (174,948
  

 

 

   

 

 

 

Proved oil and gas properties, net

     1,434,357        977,584   

Unproved oil and gas properties

     77,606        82,825   
  

 

 

   

 

 

 

Oil and gas properties, net

     1,511,963        1,060,409   

Other property and equipment

     41,333        20,859   

Less: Accumulated depreciation

     (3,922     (1,313
  

 

 

   

 

 

 

Other property and equipment, net

     37,411        19,546   
  

 

 

   

 

 

 

Total property, plant and equipment, net

   $ 1,549,374      $ 1,079,955   
  

 

 

   

 

 

 

 

 

(1) Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $15.2 million and $11.4 million at June 30, 2012 and December 31, 2011, respectively. In addition, the Company’s proved oil and gas properties include capitalized interest of $4.7 million and $3.1 million at June 30, 2012 and December 31, 2011, respectively.

As a result of expiring leases and periodic assessments of unproved properties, the Company recorded non-cash impairment charges on its unproved oil and gas properties of $2.2 million and $2.6 million for the three and six months ended June 30, 2012, respectively, and $1.5 million and $2.9 million for the three and six months ended June 30, 2011, respectively. No impairment charges on proved oil and natural gas properties were recorded for the three and six months ended June 30, 2012 or 2011.

5. Fair Value Measurements

In accordance with the Financial Accounting Standards Board’s (“FASB”) authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company recognizes its non-financial assets and liabilities, such as asset retirement obligations and proved oil and natural gas properties upon impairment, at fair value on a non-recurring basis.

As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (“exit price”). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.

The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows:

Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

 

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Level 3 — Pricing inputs are generally less observable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.

Financial Assets and Liabilities

As required, financial assets and liabilities are classified in their entirety 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 fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:

 

     At fair value as of June 30, 2012  
     Level 1      Level 2      Level 3      Total  
     (In thousands)  

Assets:

           

Money market funds

   $ 145,609       $ —         $ —         $ 145,609   

Commodity derivative instruments (see Note 6)

     —           53,424         —           53,424   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $ 145,609       $ 53,424       $ —         $ 199,033   
  

 

 

    

 

 

    

 

 

    

 

 

 
     At fair value as of December 31, 2011  
     Level 1      Level 2      Level 3      Total  
     (In thousands)  

Assets:

           

Money market funds

   $ 250,419       $ —         $ —         $ 250,419   

Commodity derivative instruments (see Note 6)

     —           —           4,362         4,362   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $ 250,419       $ —         $ 4,362       $ 254,781   
  

 

 

    

 

 

    

 

 

    

 

 

 

Liabilities:

           

Commodity derivative instruments (see Note 6)

   $ —         $ —         $ 9,412       $ 9,412   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total liabilities

   $ —         $ —         $ 9,412       $ 9,412   
  

 

 

    

 

 

    

 

 

    

 

 

 

The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the Company’s Condensed Consolidated Balance Sheet at June 30, 2012 and December 31, 2011. The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions. The Company identified the money market funds as Level 1 instruments due to the fact that the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained and there are active markets for the underlying investments.

The Level 2 and Level 3 instruments presented in the tables above consist of oil collars, put spreads and deferred premium puts. The fair values of the Company’s oil collars and deferred premium puts are based upon a third-party preparer’s calculation using mark-to-market valuation reports provided by the Company’s counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has the third-party preparer evaluate other readily available market prices for its derivative contracts as there is an active market for these contracts. The third-party preparer performs its independent valuation using an options pricing model similar to Black-Scholes. The significant inputs used are crude oil prices, volatility, skew, discount rate and the contract terms of the derivative instruments. However, the Company does not have access to the specific proprietary valuation models or inputs used by its counterparties or third-party preparer. The determination of the fair values also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculated the credit adjustment for derivatives in an asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a liability position is based on the Company’s market credit spread. Based on these calculations, the Company recorded a downward adjustment to the fair value of its net derivative asset in the amount of $0.3 million at June 30, 2012 and a downward adjustment to the fair value of its net derivative liability in the amount of $0.3 million at December 31, 2011.

The Company has adopted the FASB’s authoritative guidance amending certain accounting and disclosure requirements related to fair value measurements. The guidance clarifies and modifies some fair value measurement principles under GAAP, including a change in the valuation premise and the application of premiums and discounts, and contains some new disclosure requirements under GAAP. The guidance had no impact on the Company’s financial position, cash flows or results of operations for the six months ended June 30, 2012.

 

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The following table presents a reconciliation of the changes in fair value of the derivative instruments classified as Level 3 in the fair value hierarchy for the periods presented.

 

     2012     2011  
     (In thousands)  

Balance as of January 1

   $ (5,050   $ (10,486

Total gains or (losses) (realized or unrealized):

    

Included in earnings

     —          (4,119

Included in other comprehensive income

     —          —     

Settlements

     —          4,652   

Transfers in and out of Level 3 (1)

     5,050        —     
  

 

 

   

 

 

 

Balance as of June 30

   $ —        $ (9,953
  

 

 

   

 

 

 

Change in unrealized losses included in earnings relating to derivatives still held at June 30

   $ —        $ 533   
  

 

 

   

 

 

 

 

(1) During the first six months of 2012, the inputs used to value the Company’s commodity derivative instruments were directly or indirectly observable and those contracts were transferred to Level 2.

Fair Value of Other Financial Instruments

The Company’s financial instruments, including certain cash and cash equivalents, short-term investments, accounts receivable and accounts payable, are carried at amortized cost, which approximates cost and fair value due to the short-term maturity of these instruments. At June 30, 2012, the Company’s cash equivalents were all Level 1 assets. The carrying amount of the Company’s long-term debt (senior unsecured notes due 2019 and 2021 – see Note 7) reported in the Condensed Consolidated Balance Sheet at June 30, 2012 is $800.0 million, with a fair value of $806.0 million. The Company’s unsecured notes are publicly traded and therefore categorized as a Level 1 asset.

Nonfinancial Assets and Liabilities

Asset retirement obligations. The carrying amount of the Company’s asset retirement obligations (“ARO”) in the Condensed Consolidated Balance Sheet at June 30, 2012 is $17.3 million (see Note 8 – Asset Retirement Obligations). The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Impairment. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs. No impairment charges on proved oil and natural gas properties were recorded for the three months ended June 30, 2012 or 2011.

6. Derivative Instruments

The Company utilizes derivative financial instruments to manage risks related to changes in oil prices. As of June 30, 2012, the Company utilized put spreads, two-way collar options and three-way collar options to reduce the volatility of oil prices on a significant portion of the Company’s future expected oil production. All derivative instruments are recorded on the balance sheet as either assets or liabilities measured at fair value (see Note 5 – Fair Value Measurements). Derivative assets and liabilities arising from the Company’s derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both realized and unrealized, are recognized in the Other Income (Expense) section of the Condensed Consolidated Statement of Operations as a gain or loss on derivative instruments. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements are reflected as investing activities in the Company’s Condensed Consolidated Statement of Cash Flows.

 

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As of June 30, 2012, the Company had the following outstanding commodity derivative instruments, all of which settle monthly based on the average West Texas Intermediate crude oil index price:

 

Settlement

Period

  

Derivative
Instrument

   Total
Notional
Amount of
Oil (Barrels)
     Average Sub-Floor Price      Average
Floor Price
     Average
Ceiling Price
     Fair Value
Asset
(Liability)
 
                                      (In thousands)  

2012

   Two-Way Collars      1,189,500          $ 89.23       $ 108.76       $ 7,906   

2012

   Three-Way Collars      1,860,000       $ 66.39       $ 90.33       $ 109.70         12,093   

2013

   Two-Way Collars      201,500          $ 89.23       $ 108.76         1,533   

2013

   Three-Way Collars      2,023,420       $ 65.30       $ 92.51       $ 112.63         13,978   

2013

   Put Spreads      1,717,080       $ 70.71       $ 91.24            12,853   

2014

   Three-Way Collars      827,030       $ 71.08       $ 92.58       $ 114.15         3,714   

2014

   Put Spreads      150,970       $ 71.03       $ 91.03            1,104   

2015

   Three-Way Collars      62,000       $ 72.50       $ 92.50       $ 114.40         243   
                 

 

 

 
                  $ 53,424   
                 

 

 

 

The following table summarizes the location and fair value of all outstanding commodity derivative instruments recorded in the balance sheet for the periods presented:

 

Fair Value of Derivative Instrument Assets (Liabilities)

 
          Fair Value  

Instrument Type

   Balance Sheet Location    June 30,
2012
     December 31,
2011
 
          (In thousands)  

Crude oil collar

   Derivative instruments — current assets    $ 35,257       $ —     

Crude oil collar

   Derivative instruments — non-current assets      18,167         4,362   

Crude oil collar

   Derivative instruments — current liabilities      —           (5,907

Crude oil collar

   Derivative instruments — non-current liabilities      —           (3,505
     

 

 

    

 

 

 

Total derivative instruments

      $ 53,424       $ (5,050
     

 

 

    

 

 

 

The following table summarizes the location and amounts of realized and unrealized gains and losses from the Company’s commodity derivative instruments for the periods presented:

 

          Three Months Ended June 30,     Six Months Ended June 30,  
     

Income Statement Location

   2012     2011     2012     2011  
          (In thousands)     (In thousands)  

Change in unrealized gain/loss on derivative instruments

   Net gain (loss) on derivative instruments    $ 75,769      $ 31,687      $ 58,474      $ 533   

Realized loss on derivative instruments

   Net gain (loss) on derivative instruments      (1,174     (4,140     (2,465     (4,652
     

 

 

   

 

 

   

 

 

   

 

 

 

Total net gain (loss) on derivative instruments

      $ 74,595      $ 27,547      $ 56,009      $ (4,119
     

 

 

   

 

 

   

 

 

   

 

 

 

7. Long-Term Debt

Senior unsecured notes. During 2011, the Company issued $400.0 million of 7.25% senior unsecured notes due February 1, 2019 (the “2019 Notes”) and $400.0 million of 6.5% senior unsecured notes due November 1, 2021 (the “2021 Notes”, and together with the 2019 Notes, the “Notes”). Interest on the Notes is payable semi-annually in arrears. The Notes are guaranteed on a senior unsecured basis by the Company’s material subsidiaries (the “Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors. The issuance of these Notes resulted in aggregate net proceeds to the Company of approximately $783.4 million.

The Notes were issued under indentures containing provisions that are substantially the same, as amended and supplemented by supplemental indentures (collectively the “Indentures”), among the Company, the Guarantors and U.S. Bank National Association, as trustee (the “Trustee”). The Company has certain options to redeem up to 35% of the Notes at a certain redemption price based on a percentage of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption. Prior to certain dates, the Company has the option to redeem some or all of the Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The Company estimates that the fair value of these options is immaterial at June 30, 2012.

 

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The Indentures restrict the Company’s ability and the ability of certain of its subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to certain exceptions and qualifications. If at any time when the Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no Default (as defined in the Indentures) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries will cease to be subject to such covenants.

The Indentures contain customary events of default, including:

 

   

default in any payment of interest on any Note when due, continued for 30 days;

 

   

default in the payment of principal or premium, if any, on any Note when due;

 

   

failure by the Company to comply with its other obligations under the Indentures, in certain cases subject to notice and grace periods;

 

   

payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries (as defined in the Indentures) in the aggregate principal amount of $10.0 million or more;

 

   

certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary (as defined in the Indentures) or group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary;

 

   

failure by the Company or any Significant Subsidiary or group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary to pay certain final judgments aggregating in excess of $10.0 million within 60 days; and

 

   

any guarantee of the Notes by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker.

Senior secured revolving line of credit. OP LLC, as parent, and OPNA, as borrower, entered into a credit agreement dated June 22, 2007 (as amended and restated, the “Amended Credit Facility”). The Amended Credit Facility is restricted to the borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year. Borrowings under the Amended Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the Company’s assets, including mortgage liens on oil and natural gas properties having at least 80% of the reserve value as determined by reserve reports. On April 3, 2012, the Company entered into its sixth amendment to its Amended Credit Facility. This amendment added two new lenders to the bank group. All other terms and conditions of the Amended Credit Facility remained the same, including the October 6, 2016 maturity date and the $1 billion senior secured revolving line of credit. In connection with the sixth amendment, the semi-annual redetermination of the borrowing base was also completed on April 3, 2012, which resulted in the borrowing base of the Amended Credit Facility increasing from $350 million to $500 million. Effective April 20, 2012, the Company executed an agreement consenting to the resignation of BNP Paribas as the administrative agent and a lender under the Amended Credit Facility. Wells Fargo was appointed successor administrative agent and assumed the credit commitment of BNP Paribas. BNP Paribas remains as a counterparty for the Company’s commodity derivative instruments. In addition, on June 25, 2012, the Company’s lenders waived the mandatory reduction of the Company’s borrowing base that otherwise would have occurred as a result of the Company’s issuance of senior unsecured notes in July 2012 (see Note 13 – Subsequent Events).

Borrowings under the Amended Credit Facility are subject to varying rates of interest based on (1) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (2) whether the loan is a London interbank offered rate (“LIBOR”) loan or a domestic bank prime interest rate loan (defined in the Amended Credit Facility as an Alternate Based Rate or “ABR” loan). As of June 30, 2012, any outstanding LIBOR and ABR loans would have borne their respective interest rates plus the applicable margin indicated in the following table:

 

Ratio of Total Outstanding Borrowings to Borrowing Base

   Applicable Margin
for LIBOR Loans
  Applicable Margin
for ABR Loans

Less than .25 to 1

   1.50%   0.00%

Greater than or equal to .25 to 1 but less than .50 to 1

   1.75%   0.25%

Greater than or equal to .50 to 1 but less than .75 to 1

   2.00%   0.50%

Greater than or equal to .75 to 1 but less than .90 to 1

   2.25%   0.75%

Greater than .90 to 1 but less than or equal 1

   2.50%   1.00%

 

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Table of Contents

An ABR loan may be repaid at any time before the scheduled maturity of the Amended Credit Facility upon the Company providing advance notification to the lenders under the Amended Credit Facility (the “Lenders”). Interest is paid quarterly on ABR loans based on the number of days an ABR loan is outstanding as of the last business day in March, June, September and December. The Company has the option to convert an ABR loan to a LIBOR-based loan upon providing advance notification to the Lenders. The minimum available loan term is one month and the maximum loan term is six months for LIBOR-based loans. Interest for LIBOR loans is paid upon maturity of the loan term. Interim interest is paid every three months for LIBOR loans that have loan terms greater than three months in duration. At the end of a LIBOR loan term, the Amended Credit Facility allows the Company to elect to repay the borrowing, continue a LIBOR loan with the same or a differing loan term or convert the borrowing to an ABR loan.

On a quarterly basis, the Company also pays a 0.375% annualized commitment fee on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.

The Amended Credit Facility contains covenants that include, among others:

 

   

a prohibition against incurring debt, subject to permitted exceptions;

 

   

a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;

 

   

a prohibition against making investments, loans and advances, subject to permitted exceptions;

 

   

restrictions on creating liens and leases on the assets of the Company and its subsidiaries, subject to permitted exceptions;

 

   

restrictions on merging and selling assets outside the ordinary course of business;

 

   

restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;

 

   

a provision limiting oil and natural gas derivative financial instruments;

 

   

a requirement that the Company not allow a ratio of Total Net Debt (as defined in the Amended Credit Facility) to consolidated EBITDAX (as defined in the Amended Credit Facility) to be greater than 4.0 to 1.0 for the four quarters ended on the last day of each quarter; and

 

   

a requirement that the Company maintain a Current Ratio (as defined in the Amended Credit Facility) of consolidated current assets (with exclusions as described in the Amended Credit Facility) to consolidated current liabilities (with exclusions as described in the Amended Credit Facility) of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

The Amended Credit Facility contains customary events of default. If an event of default occurs and is continuing, the Lenders may declare all amounts outstanding under the Amended Credit Facility to be immediately due and payable.

As of June 30, 2012, the Company had no borrowings and no outstanding letters of credit issued under the Amended Credit Facility, resulting in an unused borrowing base capacity of $500 million. The Company was in compliance with the financial covenants of the Amended Credit Facility as of June 30, 2012.

Deferred financing costs. As of June 30, 2012, the Company had $25.2 million of deferred financing costs related to the Amended Credit Facility and the senior unsecured notes. The deferred financing costs are included in deferred costs and other assets on the Company’s Condensed Consolidated Balance Sheet at June 30, 2012 and are being amortized over the respective terms of the Amended Credit Facility and the senior unsecured notes. The amortization of these deferred financing costs is included in interest expense on the Company’s Condensed Consolidated Statement of Operations.

8. Asset Retirement Obligations

The following table reflects the changes in the Company’s ARO during the six months ended June 30, 2012:

 

     (In thousands)  

Balance at December 31, 2011

   $ 13,075   

Liabilities incurred during period

     2,812   

Liabilities settled during period

     —     

Accretion expense during period (1)

     389   

Revisions to estimates

     984   
  

 

 

 

Balance at June 30, 2012

   $ 17,260   
  

 

 

 

 

(1) Included in depreciation, depletion and amortization on the Company’s Condensed Consolidated Statement of Operations.

At June 30, 2012, the current portion of the total ARO balance was approximately $0.3 million and is included in accrued liabilities on the Company’s Condensed Consolidated Balance Sheet.

 

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Table of Contents

9. Income Taxes

The Company’s effective tax rate for the three and six months ended June 30, 2012 was 37.4%, and the Company’s effective tax rate for the three and six months ended June 30, 2011 was 37.8%, which were consistent with the statutory tax rate applicable to the U.S. and the blended state rate for the states in which the Company conducts business. As of June 30, 2012, the Company did not have any uncertain tax positions requiring adjustments to its tax liability.

The Company had deferred tax assets for its federal and state tax loss carryforwards at June 30, 2012 recorded in non-current deferred taxes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of June 30, 2012, management determined that a valuation allowance was not required for the tax loss carryforwards as they are expected to be fully utilized before expiration.

10. Earnings Per Share

Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the impact of potentially dilutive non-vested restricted shares outstanding during the periods presented, unless their effect is anti-dilutive. There are no adjustments made to income available to common stockholders in the calculation of diluted earnings per share.

The following is a calculation of the basic and diluted weighted-average shares outstanding for the three and six months ended June 30, 2012 and 2011:

 

     Three Months
Ended June 30,
     Six Months
Ended June 30,
 
     2012      2011      2012      2011  
     (In thousands)      (In thousands)  

Basic weighted average common shares outstanding

     92,176         92,048         92,153         92,047   

Dilution effect of stock awards at end of period

     46         103         186         130   
  

 

 

    

 

 

    

 

 

    

 

 

 

Diluted weighted average common shares outstanding

     92,222         92,151         92,339         92,177   
  

 

 

    

 

 

    

 

 

    

 

 

 

Anti-dilutive stock-based compensation awards

     634         272         397         173   
  

 

 

    

 

 

    

 

 

    

 

 

 

11. Commitments and Contingencies

Lease obligations. The Company’s total rental commitments under leases for office space and other property and equipment at June 30, 2012 were $14.7 million.

Drilling contracts. As of June 30, 2012, the Company had certain drilling rig contracts with initial terms greater than one year. In the event of early contract termination under these contracts, the Company would be obligated to pay approximately $58.5 million as of June 30, 2012 for the days remaining through the end of the primary terms of the contracts.

Volume commitment agreements. As of June 30, 2012, the Company had certain agreements with an aggregate requirement to deliver a minimum quantity of approximately 21.2 MMBbl and 16.5 Bcf from its Williston Basin project areas within a specified timeframe. Future obligations under these agreements were approximately $73.4 million as of June 30, 2012.

Fracturing services. As of June 30, 2012, the Company had certain agreements with third party fracturing service companies for an initial term greater than one year. In the event of early contract termination under these agreements, the Company would be obligated to pay approximately $31.4 million as of June 30, 2012 for the months remaining through the end of the primary terms of these agreements.

Litigation. The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. The Company believes all such matters are without merit and 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.

12. Condensed Consolidating Financial Information

The 2019 Notes and the 2021 Notes (see Note 7) are guaranteed on a senior unsecured basis by the Guarantors, which are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors. Certain of the Company’s immaterial wholly owned subsidiaries do not guarantee the Notes (“Non-Guarantor Subsidiaries”).

 

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Table of Contents

The following financial information reflects consolidating financial information of the Company (“Issuer”) and its Guarantors on a combined basis, prepared on the equity basis of accounting. The Non-Guarantor Subsidiaries are immaterial and, therefore, not presented separately. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantors operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantors because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantors. The consolidating statement of cash flows for the six months ended June 30, 2011 includes a revision in presentation in the Issuer column, which increased cash flows from operating activities by $34.4 million and reduced cash flows from financing activities by the same amount. These revisions are eliminated in consolidation and have no effect on the Guarantors or consolidated financial statements.

Condensed Consolidating Balance Sheet

(In thousands, except share data)

 

     June 30, 2012  
     Parent/
Issuer
    Combined
Guarantor
Subsidiaries
    Intercompany
Eliminations
    Consolidated  
ASSETS         

Current assets

        

Cash and cash equivalents

   $ 195,660      $ 43,226      $ —        $ 238,886   

Accounts receivable – oil and gas revenues

     —          79,478        —          79,478   

Accounts receivable – joint interest partners

     —          66,794        —          66,794   

Accounts receivable – from affiliates

     266        3,361        (3,627     —     

Inventory

     —          19,550        —          19,550   

Prepaid expenses

     63        611        —          674   

Advances to joint interest partners

     —          1,957        —          1,957   

Derivative instruments

     —          35,257        —          35,257   

Other current assets

     1        —          —          1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total current assets

     195,990        250,234        (3,627     442,597   
  

 

 

   

 

 

   

 

 

   

 

 

 

Property, plant and equipment

        

Oil and gas properties (successful efforts method)

     —          1,769,570        —          1,769,570   

Other property and equipment

     —          41,333        —          41,333   

Less: accumulated depreciation, depletion, amortization and impairment

     —          (261,529     —          (261,529
  

 

 

   

 

 

   

 

 

   

 

 

 

Total property, plant and equipment, net

     —          1,549,374        —          1,549,374   
  

 

 

   

 

 

   

 

 

   

 

 

 

Investments in and advances to subsidiaries

     1,313,402        —          (1,313,402     —     

Derivative instruments

     —          18,167        —          18,167   

Deferred income taxes

     24,980        —          (24,980     —     

Deferred costs and other assets

     22,132        4,100        —          26,232   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

   $ 1,556,504      $ 1,821,875      $ (1,342,009   $ 2,036,370   
  

 

 

   

 

 

   

 

 

   

 

 

 
LIABILITIES AND STOCKHOLDERS’ EQUITY         

Current liabilities

        

Accounts payable

   $ —        $ 1,010      $ —        $ 1,010   

Accounts payable – from affiliates

     3,361        266        (3,627     —     

Advances from joint interest partners

     —          28,444        —          28,444   

Revenues and production taxes payable

     —          56,795        —          56,795   

Accrued liabilities

     7,312        230,382        —          237,694   

Accrued interest payable

     16,417        10        —          16,427   

Deferred income taxes

     —          11,780        —          11,780   

Other current liabilities

     —          2,895        —          2,895   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total current liabilities

     27,090        331,582        (3,627     355,045   
  

 

 

   

 

 

   

 

 

   

 

 

 

Long-term debt

     800,000        —          —          800,000   

Asset retirement obligations

     —          16,982        —          16,982   

Deferred income taxes

     —          158,158        (24,980     133,178   

Other liabilities

     —          1,751        —          1,751   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities

     827,090        508,473        (28,607     1,306,956   
  

 

 

   

 

 

   

 

 

   

 

 

 

Stockholders’ equity

        

Capital contributions from affiliates

     —          1,183,810        (1,183,810     —     

Common stock, $0.01 par value; 300,000,000 shares authorized; 93,185,023 issued and 93,122,353 outstanding

     922        —          —          922   

Treasury stock, at cost; 62,670 shares

     (1,808     —          —          (1,808

Additional paid-in-capital

     651,271        8,743        (8,743     651,271   

Retained earnings

     79,029        120,849        (120,849     79,029   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total stockholders’ equity

     729,414        1,313,402        (1,313,402     729,414   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities and stockholders’ equity

   $ 1,556,504      $ 1,821,875      $ (1,342,009   $ 2,036,370   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

13


Table of Contents

Condensed Consolidating Balance Sheet

(In thousands, except share data)

 

     December 31, 2011  
     Parent/
Issuer
    Combined
Guarantor
Subsidiaries
    Intercompany
Eliminations
    Consolidated  
ASSETS         

Current assets

        

Cash and cash equivalents

   $ 443,482      $ 27,390      $ —        $ 470,872   

Short-term investments

     19,994        —          —          19,994   

Accounts receivable – oil and gas revenues

     —          52,164        —          52,164   

Accounts receivable – joint interest partners

     —          67,268        —          67,268   

Accounts receivable – from affiliates

     88        1,540        (1,628     —     

Inventory

     —          3,543        —          3,543   

Prepaid expenses

     309        1,831        —          2,140   

Advances to joint interest partners

     —          3,935        —          3,935   

Deferred income taxes

     —          3,233        —          3,233   

Other current assets

     18        473        —          491   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total current assets

     463,891        161,377        (1,628     623,640   
  

 

 

   

 

 

   

 

 

   

 

 

 

Property, plant and equipment

        

Oil and gas properties (successful efforts method)

     —          1,235,357        —          1,235,357   

Other property and equipment

     —          20,859        —          20,859   

Less: accumulated depreciation, depletion, amortization and impairment

     —          (176,261     —          (176,261
  

 

 

   

 

 

   

 

 

   

 

 

 

Total property, plant and equipment, net

     —          1,079,955        —          1,079,955   
  

 

 

   

 

 

   

 

 

   

 

 

 

Investments in and advances to subsidiaries

     958,880        —          (958,880     —     

Derivative instruments

     —          4,362        —          4,362   

Deferred income taxes

     13,158        —          (13,158     —     

Deferred costs and other assets

     15,742        3,683        —          19,425   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

   $ 1,451,671      $ 1,249,377      $ (973,666   $ 1,727,382   
  

 

 

   

 

 

   

 

 

   

 

 

 
LIABILITIES AND STOCKHOLDERS’ EQUITY         

Current liabilities

        

Accounts payable

   $ 23      $ 12,184      $ —        $ 12,207   

Accounts payable – from affiliates

     1,540        88        (1,628     —     

Advances from joint interest partners

     —          9,064        —          9,064   

Revenues and production taxes payable

     —          19,468        —          19,468   

Accrued liabilities

     103        119,589        —          119,692   

Accrued interest payable

     15,767        7        —          15,774   

Derivative instruments

     —          5,907        —          5,907   

Other current liabilities

     —          472        —          472   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total current liabilities

     17,433        166,779        (1,628     182,584   
  

 

 

   

 

 

   

 

 

   

 

 

 

Long-term debt

     800,000        —          —          800,000   

Asset retirement obligations

     —          13,075        —          13,075   

Derivative instruments

     —          3,505        —          3,505   

Deferred income taxes

     —          106,141        (13,158     92,983   

Other liabilities

     —          997        —          997   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities

     817,433        290,497        (14,786     1,093,144   
  

 

 

   

 

 

   

 

 

   

 

 

 

Stockholders’ equity

        

Capital contributions from affiliates

     —          941,575        (941,575     —     

Common stock, $0.01 par value; 300,000,000 shares authorized; 92,483,393 issued and 92,460,914 outstanding

     921        —          —          921   

Treasury stock, at cost; 22,479 shares

     (602     —          —          (602

Additional paid-in-capital

     647,374        8,743        (8,743     647,374   

Retained earnings (deficit)

     (13,455     8,562        (8,562     (13,455
  

 

 

   

 

 

   

 

 

   

 

 

 

Total stockholders’ equity

     634,238        958,880        (958,880     634,238   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities and stockholders’ equity

   $ 1,451,671      $ 1,249,377      $ (973,666   $ 1,727,382   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

14


Table of Contents

Condensed Consolidating Statement of Operations

(In thousands)

 

     Three Months Ended June 30, 2012  
     Parent/
Issuer
    Combined
Guarantor
Subsidiaries
    Intercompany
Eliminations
    Consolidated  

Revenues

        

Oil and gas revenues

   $ —        $ 145,203      $ —        $ 145,203   

Well services revenues

     —          3,861        —          3,861   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     —          149,064        —          149,064   
  

 

 

   

 

 

   

 

 

   

 

 

 

Expenses

        

Lease operating expenses

     —          12,029        —          12,029   

Well services operating expenses

     —          1,207        —          1,207   

Marketing, transportation and gathering expenses

     —          1,970        —          1,970   

Production taxes

     —          13,720        —          13,720   

Depreciation, depletion and amortization

     —          44,213        —          44,213   

Impairment of oil and gas properties

     —          2,203        —          2,203   

General and administrative expenses

     2,644        10,893        —          13,537   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

     2,644        86,235        —          88,879   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     (2,644     62,829        —          60,185   
  

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense)

        

Equity in earnings in subsidiaries

     86,024        —          (86,024     —     

Net gain on derivative instruments

     —          74,595        —          74,595   

Interest expense

     (13,414     (660     —          (14,074

Other income

     118        658        —          776   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     72,728        74,593        (86,024     61,297   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

     70,084        137,422        (86,024     121,482   

Income tax benefit (expense)

     5,959        (51,398     —          (45,439
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 76,043      $ 86,024      $ (86,024   $ 76,043   
  

 

 

   

 

 

   

 

 

   

 

 

 

Condensed Consolidating Statement of Operations

(In thousands)

 

     Three Months Ended June 30, 2011  
     Parent/
Issuer
    Combined
Guarantor
Subsidiaries
    Intercompany
Eliminations
    Consolidated  

Oil and gas revenues

   $ —        $ 67,206      $ —        $ 67,206   

Expenses

        

Lease operating expenses

     —          5,951        —          5,951   

Marketing, transportation and gathering expenses

     —          247        —          247   

Production taxes

     —          7,085        —          7,085   

Depreciation, depletion and amortization

     —          13,100        —          13,100   

Exploration expenses

     —          259        —          259   

Impairment of oil and gas properties

     —          1,536        —          1,536   

General and administrative expenses

     1,318        5,296        —          6,614   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

     1,318        33,474        —          34,792   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     (1,318     33,732        —          32,414   
  

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense)

        

Equity in earnings in subsidiaries

     37,557        —          (37,557     —     

Net gain on derivative instruments

     —          27,547        —          27,547   

Interest expense

     (6,473     (288     —          (6,761

Other income

     371        8        —          379   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     31,455        27,267        (37,557     21,165   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

     30,137        60,999        (37,557     53,579   

Income tax benefit (expense)

     3,212        (23,442     —          (20,230
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 33,349      $ 37,557      $ (37,557   $ 33,349   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

15


Table of Contents

Condensed Consolidating Statement of Operations

(In thousands)

 

     Six Months Ended June 30, 2012  
     Parent/
Issuer
    Combined
Guarantor
Subsidiaries
    Intercompany
Eliminations
    Consolidated  

Revenues

        

Oil and gas revenues

   $ —        $ 283,109      $ —        $ 283,109   

Well services revenues

     —          4,521        —          4,521   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     —          287,630        —          287,630   
  

 

 

   

 

 

   

 

 

   

 

 

 

Expenses

        

Lease operating expenses

     —          21,845        —          21,845   

Well services operating expenses

     —          1,684        —          1,684   

Marketing, transportation and gathering expenses

     —          4,539        —          4,539   

Production taxes

     —          26,986        —          26,986   

Depreciation, depletion and amortization

     —          83,099        —          83,099   

Exploration expenses

     —          2,835        —          2,835   

Impairment of oil and gas properties

     —          2,571        —          2,571   

General and administrative expenses

     5,090        20,646        —          25,736   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

     5,090        164,205        —          169,295   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     (5,090     123,425        —          118,335   
  

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense)

        

Equity in earnings in subsidiaries

     112,286        —          (112,286     —     

Net gain on derivative instruments

     —          56,009        —          56,009   

Interest expense

     (26,829     (1,144     —          (27,973

Other income

     295        1,079        —          1,374   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     85,752        55,944        (112,286     29,410   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

     80,662        179,369        (112,286     147,745   

Income tax benefit (expense)

     11,822        (67,083     —          (55,261
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 92,484      $ 112,286      $ (112,286   $ 92,484   
  

 

 

   

 

 

   

 

 

   

 

 

 

Condensed Consolidating Statement of Operations

(In thousands)

 

     Six Months Ended June 30, 2011  
     Parent/
Issuer
    Combined
Guarantor
Subsidiaries
    Intercompany
Eliminations
    Consolidated  

Oil and gas revenues

   $ —        $ 125,950      $ —        $ 125,950   

Expenses

        

Lease operating expenses

     —          11,581        —          11,581   

Marketing, transportation and gathering expenses

     —          559        —          559   

Production taxes

     —          13,168        —          13,168   

Depreciation, depletion and amortization

     —          26,912        —          26,912   

Exploration expenses

     —          291        —          291   

Impairment of oil and gas properties

     —          2,917        —          2,917   

General and administrative expenses

     2,581        9,983        —          12,564   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

     2,581        65,411        —          67,992   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     (2,581     60,539        —          57,958   
  

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense)

        

Equity in earnings in subsidiaries

     34,387        —          (34,387     —     

Net loss on derivative instruments

     —          (4,119     —          (4,119

Interest expense

     (11,414     (545     —          (11,959

Other income

     664        27        —          691   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     23,637        (4,637     (34,387     (15,387
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

     21,056        55,902        (34,387     42,571   

Income tax benefit (expense)

     5,446        (21,515     —          (16,069
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 26,502      $ 34,387      $ (34,387   $ 26,502   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

16


Table of Contents

Condensed Consolidating Statement of Cash Flows

(In thousands)

 

     Six Months Ended June 30, 2012  
     Parent/
Issuer
    Combined
Guarantor
Subsidiaries
    Intercompany
Eliminations
    Consolidated  

Cash flows from operating activities:

        

Net income

   $ 92,484      $ 112,286      $ (112,286   $ 92,484   

Adjustments to reconcile net income to net cash provided by (used in) operating activities:

        

Equity in earnings of subsidiaries

     (112,286     —          112,286        —     

Depreciation, depletion and amortization

     —          83,099        —          83,099   

Impairment of oil and gas properties

     —          2,571        —          2,571   

Deferred income taxes

     (11,822     66,983        —          55,161   

Derivative instruments

     —          (56,009     —          (56,009

Stock-based compensation expenses

     3,793        105        —          3,898   

Debt discount amortization and other

     960        305        —          1,265   

Working capital and other changes:

        

Change in accounts receivable

     (178     (28,661     1,999        (26,840

Change in inventory

     —          (21,636     —          (21,636

Change in prepaid expenses

     246        1,254        —          1,500   

Change in other current assets

     17        473        —          490   

Change in other assets

     (7,305     (60     —          (7,365

Change in accounts payable and accrued liabilities

     9,657        32,364        (1,999     40,022   

Change in other current liabilities

     —          2,470        —          2,470   

Change in other liabilities

     —          750        —          750   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) operating activities

     (24,434     196,294        —          171,860   
  

 

 

   

 

 

   

 

 

   

 

 

 

Cash flows from investing activities:

        

Capital expenditures

     —          (440,781     —          (440,781

Derivative settlements

     —          (2,465     —          (2,465

Redemptions of short-term investments

     19,994        —          —          19,994   

Advances to joint interest partners

     —          1,978        —          1,978   

Advances from joint interest partners

     —          19,380        —          19,380   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) investing activities

     19,994        (421,888     —          (401,894
  

 

 

   

 

 

   

 

 

   

 

 

 

Cash flows from financing activities:

        

Purchases of treasury stock

     (1,206     —          —          (1,206

Debt issuance costs

     (46     (700     —          (746

Investment in / capital contributions from affiliates

     (242,130     242,130        —          —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     (243,382     241,430        —          (1,952
  

 

 

   

 

 

   

 

 

   

 

 

 

Increase (decrease) in cash and cash equivalents

     (247,822     15,836        —          (231,986

Cash and cash equivalents at beginning of period

     443,482        27,390        —          470,872   
  

 

 

   

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 195,660      $ 43,226      $ —        $ 238,886   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

17


Table of Contents

Condensed Consolidating Statement of Cash Flows

(In thousands)

 

     Six Months Ended June 30, 2011  
     Parent/
Issuer
    Combined
Guarantor
Subsidiaries
    Intercompany
Eliminations
    Consolidated  

Cash flows from operating activities:

        

Net income

   $ 26,502      $ 34,387      $ (34,387   $ 26,502   

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

        

Equity in earnings of subsidiaries

     (34,387     —          34,387        —     

Depreciation, depletion and amortization

     —          26,912        —          26,912   

Impairment of oil and gas properties

     —          2,917        —          2,917   

Deferred income taxes

     (5,446     21,515        —          16,069   

Derivative instruments

     —          4,119        —          4,119   

Stock-based compensation expenses

     1,571        —          —          1,571   

Debt discount amortization and other

     489        159        —          648   

Working capital and other changes:

        

Change in accounts receivable

     —          (20,940     995        (19,945

Change in inventory

     —          (65     —          (65

Change in prepaid expenses

     (382     128        —          (254

Change in other current assets

     (211     —          —          (211

Change in other assets

     (100     (3     —          (103

Change in accounts payable and accrued liabilities

     13,013        31,594        (995     43,612   

Change in other liabilities

     —          323        —          323   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     1,049        101,046        —          102,095   
  

 

 

   

 

 

   

 

 

   

 

 

 

Cash flows from investing activities:

        

Capital expenditures

     —          (212,267     —          (212,267

Derivative settlements

     —          (4,652     —          (4,652

Purchases of short-term investments

     (164,913     —          —          (164,913

Redemptions of short-term investments

     39,974        —          —          39,974   

Advances to joint interest partners

     —          983        —          983   

Advances from joint interest partners

     —          5,851        —          5,851   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (124,939     (210,085     —          (335,024
  

 

 

   

 

 

   

 

 

   

 

 

 

Cash flows from financing activities:

        

Proceeds from issuance of senior notes

     400,000        —          —          400,000   

Purchases of treasury stock

     (559     —          —          (559

Debt issuance costs

     (9,650     (377     —          (10,027

Investment in / capital contributions from affiliates

     (111,078     111,078        —          —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by financing activities

     278,713        110,701        —          389,414   
  

 

 

   

 

 

   

 

 

   

 

 

 

Increase in cash and cash equivalents

     154,823        1,662        —          156,485   

Cash and cash equivalents at beginning of period

     119,940        23,580        —          143,520   
  

 

 

   

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 274,763      $ 25,242      $ —        $ 300,005   
  

 

 

   

 

 

   

 

 

   

 

 

 

13. Subsequent Events

The Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than as noted below.

Senior unsecured notes. On July 2, 2012, the Company issued $400 million of 6.875% senior unsecured notes due January 15, 2023 (the “2023 Notes”). Interest is payable on the 2023 Notes semi-annually in arrears on January 15 and July 15 of each year, beginning on January 15, 2013. The 2023 Notes are jointly and severally guaranteed on a senior unsecured basis by all of the Company’s existing material subsidiaries. The issuance of the 2023 Notes resulted in net proceeds to the Company of approximately $392 million, which the Company will use to fund its exploration, development and acquisition program and for general corporate purposes. The issuance and sale of the 2023 Notes has been registered under the Securities Act of 1933 pursuant to an automatic shelf Registration Statement on Form S-3 (Registration No. 333-175603), as amended, of the Company, filed with the SEC on July 15, 2011.

Derivative instruments. In July 2012, the Company entered into new two-way costless collar options, all of which settle monthly based on the West Texas Intermediate crude oil index price, for a total notional amount of 183,000 barrels in 2012, 1,215,500 barrels in 2013 and 108,500 barrels in 2014. These derivative instruments do not qualify for and were not designated as hedging instruments for accounting purposes.

 

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Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed below and detailed under Item 1A. “Risk Factors” in our 2011 Annual Report and in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2012, could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, or implied in such forward-looking statements.

Forward-looking statements may include statements about:

 

   

our business strategy;

 

   

estimated future net reserves and present value thereof;

 

   

technology;

 

   

cash flows and liquidity;

 

   

our financial strategy, budget, projections, execution of business plan and operating results;

 

   

oil and natural gas realized prices;

 

   

timing and amount of future production of oil and natural gas;

 

   

availability of drilling, completion and production equipment and materials;

 

   

availability of qualified personnel;

 

   

owning and operating a services company;

 

   

the amount, nature and timing of capital expenditures;

 

   

availability and terms of capital;

 

   

property acquisitions;

 

   

costs of exploiting and developing our properties and conducting other operations;

 

   

drilling and completion of wells;

 

   

infrastructure for salt water disposal;

 

   

gathering, transportation and marketing of oil and natural gas, both in the Williston Basin and domestically;

 

   

general economic conditions;

 

   

operating environment, including inclement weather conditions;

 

   

competition in the oil and natural gas industry;

 

   

effectiveness of risk management activities;

 

   

environmental liabilities;

 

   

counterparty credit risk;

 

   

governmental regulation and the taxation of the oil and natural gas industry;

 

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developments in oil-producing and natural gas-producing countries;

 

   

uncertainty regarding future operating results; and

 

   

plans, objectives, expectations and intentions contained in this report that are not historical.

All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We disclaim any obligation to update or revise these statements unless required by securities law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Quarterly Report on Form 10-Q, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Overview

We are an independent exploration and production company focused on the acquisition and development of unconventional oil and natural gas resources primarily in the Montana and North Dakota regions of the Williston Basin. Since our inception, we have acquired properties that provide current production and significant upside potential through further development. Our drilling activity is primarily directed toward projects that we believe can provide us with repeatable successes in the Bakken and Three Forks formations. We also operate businesses that are complementary to our primary development and production activities, including a marketing business, Oasis Petroleum Marketing LLC (“OPM”), and a well services business, Oasis Well Services LLC (“OWS”). The revenues and expenses related to work performed by OPM and OWS for Oasis Petroleum North America LLC’s working interests are eliminated in consolidation and, therefore, do not directly contribute to our consolidated results of operations.

Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe will meet or exceed our rate of return criteria. For acquisitions of properties with additional development, exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. In some instances, we have acquired non-operated property interests at what we believe to be attractive rates of return either because they provided a foothold in a new area of interest or complemented our existing operations. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives. In addition, the acquisition of non-operated properties in new areas provides us with geophysical and geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis.

Due to the geographic concentration of our oil and natural gas properties in the Williston Basin, we believe the primary sources of opportunities, challenges and risks related to our business for both the short and long-term are:

 

   

Commodity prices for oil and natural gas;

 

   

Transportation capacity;

 

   

Availability and cost of services; and

 

   

Availability of qualified personnel.

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations. We enter into crude oil sales contracts with purchasers who have access to crude oil transportation capacity, utilize derivative financial instruments to manage our commodity price risk, and enter into physical delivery contracts to manage our price differentials. In an effort to improve price realizations from the sale of our oil and natural gas, we manage our commodities marketing activities in-house, which enables us to market and sell our oil and natural gas to a broader array of potential purchasers. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations or cash flows. Additionally, during the first and second quarters of 2012, we began to actively increase the number of operated wells that we have connected to a third-party oil gathering system in our West Williston project area. At the end of June 2012, the Company had 94 operated wells connected, up from only three operated wells that were connected at the beginning of 2012. We currently flow approximately 60% of our gross operated oil production on the third-party oil gathering system.

 

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Changes in commodity prices may also significantly affect the economic viability of drilling projects as well as the economic valuation and economic recovery of oil and gas reserves. Oil prices have increased significantly since 2009. As a result of higher commodity prices and continued successes in the application of completion technologies in the Bakken formation, there were more than 225 active drilling rigs in the Williston Basin at June 30, 2012. Although additional Williston Basin transportation takeaway capacity was added in recent months, production also increased due to the elevated drilling activity. The increased production coupled with the refinery and transportation constraints caused price differentials in the first and second quarters of 2012 to be at and above the high end of the historical average range of approximately 10% to 15% of the price quoted for NYMEX West Texas Intermediate (“WTI”) crude oil.

Our large concentrated acreage position potentially provides us with a multi-year inventory of drilling projects and requires some forward planning visibility for obtaining services. Our ability to develop and hold our existing undeveloped leasehold acreage is primarily dependent upon having access to drilling rigs and completion services. The utilization of existing drilling rigs and of existing completion service equipment in the Williston Basin is at an all-time high. This has resulted in drilling rigs, completion equipment and crews being imported from Canada and other parts of the United States. To ensure access to drilling rigs, we have entered into fixed-term drilling rig contracts for periods of up to three years and currently have ten drilling rigs under contract. In order to ensure the availability of completion services and the timely fracture stimulation of newly drilled wells, we formed OWS in June 2011 to provide well services on our operated wells, in addition to entering into fracturing service contracts with third party companies.

Second Quarter 2012 Highlights:

 

   

We completed and placed on production 26 gross (20.3 net) operated wells in the Williston Basin during the three months ended June 30, 2012;

 

   

We had 30 gross (24.1 net) operated wells awaiting completion and 9 gross (7.4 net) operated wells in the process of being drilled in the Bakken and Three Forks formations at June 30, 2012;

 

   

Average daily production was 20,353 Boe per day during the three months ended June 30, 2012;

 

   

Net gas production increased to 11.2 MMcfpd during the three months ended June 30, 2012 due to connecting additional wells in the Williston Basin to third-party infrastructure;

 

   

Exploration and production (“E&P”) capital expenditures were $263.2 million, consisting primarily of $243.4 million in drilling expenditures during the three months ended June 30, 2012;

 

   

At June 30, 2012, we had $238.9 million of cash and cash equivalents and had no outstanding debt or outstanding letters of credit under our revolving credit facility; and

 

   

On June 27, 2012, we priced an offering of $400 million of 6.875% senior unsecured notes due January 15, 2023. The issuance closed on July 2, 2012, resulting in net proceeds to us of approximately $392 million.

Results of Operations

Revenues

Our revenues are derived from the sale of oil and natural gas production and do not include the effects of derivative instruments. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

 

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The following table summarizes our revenues and production data for the periods indicated.

 

     Three Months Ended June 30,     Six Months Ended June 30,  
     2012      2011      Change     2012      2011      Change  

Operating results (in thousands):

                

Revenues

                

Oil

   $ 138,559       $ 65,400       $ 73,159      $ 269,935       $ 122,572       $ 147,363   

Natural gas

     6,644         1,806         4,838        13,174         3,378         9,796   

Well services

     3,861         —           3,861        4,521         —           4,521   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Total oil and gas revenues

     149,064         67,206         81,858        287,630         125,950         161,680   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Production data:

                

Oil (MBbls)

     1,682         685         997        3,156         1,379         1,777   

Natural gas (MMcf)

     1,019         200         819        1,803         402         1,401   

Oil equivalents (MBoe)

     1,852         718         1,134        3,457         1,446         2,011   

Average daily production (Boe/d)

     20,353         7,893         12,460        18,993         7,991         11,002   

Average sales prices:

                

Oil, without realized derivatives (per Bbl) (1)

   $ 82.36       $ 95.48       $ (13.12   $ 85.04       $ 88.86       $ (3.82

Oil, with realized derivatives (per Bbl) (1) (2)

     81.67         89.43         (7.76     84.26         85.49         (1.23

Natural gas (per Mcf) (3)

     6.52         9.05         (2.53     7.30         8.41         (1.11

 

(1) For the six months ended June 30, 2012, average sales prices for oil are calculated using total oil revenues, excluding bulk purchase sales of $1.5 million, divided by oil production.
(2) Realized prices include realized gains or losses on cash settlements for commodity derivatives, which do not qualify for and were not designated as hedging instruments for accounting purposes.
(3) Natural gas prices include the value for natural gas and natural gas liquids.

Three months ended June 30, 2012 as compared to three months ended June 30, 2011

Total revenues. Our total revenues increased $81.9 million, or 122%, to $149.1 million during the three months ended June 30, 2012 as compared to the three months ended June 30, 2011. Our primary revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 12,460 Boe per day, or 158%, to 20,353 Boe per day during the three months ended June 30, 2012 as compared to the three months ended June 30, 2011. The increase in average daily production sold was primarily a result of our well completions during the last two quarters of 2011 and the first two quarters of 2012. Well completions in our West Williston, East Nesson and Sanish project areas increased average daily production by approximately 9,266 Boe per day, 2,584 Boe per day and 712 Boe per day, respectively, during the second quarter of 2012 as compared to the second quarter of 2011. Average oil sales prices, without realized derivatives, decreased by $13.12/Bbl, or 14%, to an average of $82.36/Bbl for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011. The higher production amounts sold increased revenues by $87.5 million, while lower oil and natural gas sales prices decreased revenues by $9.5 million during the three months ended June 30, 2012. The remaining $3.9 million increase in total revenues was attributable to well services revenues during the three months ended June 30, 2012. There were no well services revenues during the second quarter of 2011 because OWS did not commence fracturing activity until the first quarter of 2012.

Six months ended June 30, 2012 as compared to six months ended June 30, 2011

Total revenues. Our total revenues increased $161.7 million, or 128%, to $287.6 million during the six months ended June 30, 2012 as compared to the six months ended June 30, 2011. Our primary revenues are a function of oil and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 11,002 Boe per day, or 138%, to 18,993 Boe per day during the six months ended June 30, 2012 as compared to the six months ended June 30, 2011. The increase in average daily production sold was primarily a result of our well completions during the last two quarters of 2011 and the first two quarters of 2012. Well completions in our West Williston, East Nesson and Sanish project areas increased average daily production by approximately 8,542 Boe per day, 2,043 Boe per day and 451 Boe per day, respectively, during the six months ended June 30, 2012 as compared to the six months ended June 30, 2011. Average oil sales prices, without realized derivatives, decreased by $3.82/Bbl, or 4%, to an average of $85.04/Bbl for the six months ended June 30, 2012 as compared to the six months ended June 30, 2011. The higher production amounts sold increased revenues by $161.3 million, while lower oil and natural gas sales prices decreased revenues by $5.7 million during the six months ended June 30, 2012. Well services revenues were $4.5 million for the six months ended June 30, 2012 compared to no well services revenues during the six months ended June 30, 2011 because OWS did not commence fracturing activity until the first quarter of 2012. The remaining $1.5 million increase in total revenues was attributable to oil bulk purchase revenues related to marketing activities included in oil and gas revenues during the six months ended June 30, 2012.

 

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Expenses

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

 

     Three Months Ended June 30,     Six Months Ended June 30,  
     2012     2011     $ Change     2012     2011     $ Change  
     (In thousands, except per Boe of production)  

Expenses:

            

Lease operating expenses

   $ 12,029      $ 5,951      $ 6,078      $ 21,845      $ 11,581      $ 10,264   

Well services operating expenses

     1,207        —          1,207        1,684        —          1,684   

Marketing, transportation and gathering expenses

     1,970        247        1,723        4,539        559        3,980   

Production taxes

     13,720        7,085        6,635        26,986        13,168        13,818   

Depreciation, depletion and amortization

     44,213        13,100        31,113        83,099        26,912        56,187   

Exploration expenses

     —          259        (259     2,835        291        2,544   

Impairment of oil and gas properties

     2,203        1,536        667        2,571        2,917        (346

General and administrative expenses

     13,537        6,614        6,923        25,736        12,564        13,172   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

   $ 88,879      $ 34,792      $ 54,087      $ 169,295      $ 67,992      $ 101,303   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     60,185        32,414        27,771        118,335        57,958        60,377   

Other income (expense):

            

Net gain (loss) on derivative instruments

     74,595        27,547        47,048        56,009        (4,119     60,128   

Interest expense

     (14,074     (6,761     (7,313     (27,973     (11,959     (16,014

Other income

     776        379        397        1,374        691        683   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     61,297        21,165        40,132        29,410        (15,387     44,797   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income before income taxes

     121,482        53,579        67,903        147,745        42,571        105,174   

Income tax expense

     45,439        20,230        25,209        55,261        16,069        39,192   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ 76,043      $ 33,349      $ 42,694      $ 92,484      $ 26,502      $ 65,982   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cost and expense (per Boe of production):

            

Lease operating expenses (1)

   $ 6.49      $ 8.29      $ (1.80   $ 6.32      $ 8.00      $ (1.68

Marketing, transportation and gathering expenses

     1.06        0.34        0.72        1.31        0.39        0.92   

Production taxes

     7.41        9.86        (2.45     7.81        9.10        (1.29

Depreciation, depletion and amortization

     23.87        18.24        5.63        24.04        18.61        5.43   

General and administrative expenses (2)

     7.31        9.21        (1.90     7.45        8.69        (1.24

 

(1) For the three and six months ended June 30, 2011, lease operating expenses excludes marketing, transportation and gathering expenses to conform such amount to current year classifications.
(2) Includes $1.1 million and $2.7 million of expenses related to OWS for the three and six months ended June 30, 2012, respectively. Excluding OWS, E&P only G&A would be $6.71 and $6.66 per Boe for the three and six months ended June 30, 2012, respectively.

Three months ended June 30, 2012 compared to three months ended June 30, 2011

Lease operating expenses. Lease operating expenses increased $6.1 million to $12.0 million for the three months ended June 30, 2012 compared to the three months ended June 30, 2011. This increase was due to an increased number of producing wells and increased workover expenses period over period. The unit operating costs decreased from $8.29 per Boe for the three months ended June 30, 2011 to $6.49 per Boe for the three months ended June 30, 2012, as a result of operational efficiency and lower salt water disposal (“SWD”) costs.

We have $74 million in our 2012 capital budget primarily allocated to building SWD infrastructure, which is currently being deployed in our key operating areas. This infrastructure is expected to reduce our dependence on trucks for water hauling and simplify operational logistics. As of June 30, 2012, we had approximately 30% of operated water production flowing through our operated pipeline system. We expect to have approximately 80% of operated water production flowing through the pipeline system by year-end 2012. Additionally, we currently dispose of approximately 60% of our operated water production at our operated disposal wells. This continued expansion of our SWD systems is expected to reduce lease operating expenses throughout the remainder of 2012.

Well services operating expenses. The $1.2 million in well services operating expenses represents non-affiliated fracturing service costs incurred by OWS for fracturing jobs completed in the second quarter of 2012. There were no well services operating expenses during the second quarter of 2011 because OWS did not commence fracturing activity until the first quarter of 2012.

Marketing, transportation and gathering expenses. This line item includes all of our marketing, transportation and gathering for our oil production as well as bulk oil purchase costs. The $1.7 million increase quarter over quarter, or $0.72 increase per Boe, is mainly attributable to increased oil transportation costs related to OPM, which did not commence operations until the third quarter of 2011.

Production taxes. Our production taxes for the three months ended June 30, 2012 and 2011 were 9.5% and 10.5%, respectively, as a percentage of oil and natural gas sales. The second quarter 2012 production tax rate was lower than the second quarter 2011 production tax rate primarily due to certain new wells in Montana that are subject to lower incentivized production tax rates.

 

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Depreciation, depletion and amortization (DD&A). DD&A expense increased $31.1 million to $44.2 million for the three months ended June 30, 2012 compared to the three months ended June 30, 2011. This increase in DD&A expense for the three months ended June 30, 2012 was primarily a result of our production increases from our well completions during the last two quarters of 2011 and the first two quarters of 2012. The DD&A rate for the three months ended June 30, 2012 was $23.87 per Boe compared to $18.24 per Boe for the three months ended June 30, 2011. The higher DD&A rate was due to a greater increase in well costs over an increase in reserves.

Impairment of oil and gas properties. During the three months ended June 30, 2012 and 2011, we recorded non-cash impairment charges of $2.2 million and $1.5 million, respectively, for unproved property leases that expired during the period or have been forecasted to expire under our current drilling plans. No impairment charges of proved oil and gas properties were recorded for the three months ended June 30, 2012 or 2011.

General and administrative expenses. Our general and administrative (“G&A”) expenses increased $6.9 million for the three months ended June 30, 2012 from $6.6 million for the three months ended June 30, 2011. Of this increase, approximately $6.0 million related to employee compensation expenses due to our organizational growth, including the addition of OWS, and $1.3 million was due to additional amortization of our restricted stock awards during the three months ended June 30, 2012. As of June 30, 2012, we had 223 full-time employees compared to 88 full-time employees as of June 30, 2011. Excluding G&A expenses related to OWS of $1.1 million, G&A related to E&P on a per Boe basis would have been $6.71 in the second quarter of 2012.

Derivative instruments. As a result of our derivative activities, we incurred cash settlement net losses of $1.2 million and $4.1 million for the three months ended June 30, 2012 and 2011, respectively. In addition, as a result of forward oil price changes, we recognized a $75.8 million and a $31.7 million non-cash unrealized mark-to-market net derivative gain during the three months ended June 30, 2012 and 2011, respectively.

Interest expense. Interest expense increased $7.3 million to $14.1 million for the three months ended June 30, 2012 compared to the three months ended June 30, 2011. The increase was primarily the result of interest expense incurred on our senior unsecured notes issued in November 2011 at an interest rate of 6.5%. There were no borrowings under our revolving credit facility during the three months ended June 30, 2012 and 2011, respectively.

Income taxes. Income tax expense for the three months ended June 30, 2012 and 2011 was recorded at 37.4% and 37.8% of pre-tax net income, respectively. Our effective tax rate is expected to continue to closely approximate the statutory rate applicable to the U.S. and the blended state rate of the states in which we conduct business.

Six months ended June 30, 2012 compared to six months ended June 30, 2011

Lease operating expenses. Lease operating expenses increased $10.3 million to $21.8 million for the six months ended June 30, 2012 compared to the six months ended June 30, 2011. This increase was due to an increased number of producing wells and increased workover expenses period over period. The unit operating costs decreased from $8.00 per Boe for the six months ended June 30, 2011 to $6.32 per Boe for the six months ended June 30, 2012, as a result of operational efficiency and lower SWD costs.

Well services operating expenses. The $1.7 million in well services operating expenses represents non-affiliated fracturing service costs incurred by OWS for fracturing jobs completed in 2012. There were no well services operating expenses in 2011 because OWS did not commence fracturing activity until the first quarter of 2012.

Marketing, transportation and gathering expenses. This line item includes all of our marketing, transportation and gathering for our oil production as well as bulk oil purchase costs. The $4.0 million increase period over period, or $0.92 increase per Boe, is mainly attributable to increased oil transportation costs related to OPM, which did not commence operations until the third quarter of 2011.

Production taxes. Our production taxes for the six months ended June 30, 2012 and 2011 were 9.6% and 10.5%, respectively, as a percentage of oil and natural gas sales. The production tax rate for the six months ended June 30, 2012 was lower than the production tax rate for the six months ended June 30, 2011 primarily due to certain new wells in Montana that are subject to lower incentivized production tax rates.

Depreciation, depletion and amortization (DD&A). DD&A expense increased $56.2 million to $83.1 million for the six months ended June 30, 2012 compared to the six months ended June 30, 2011. This increase in DD&A expense for the six months ended June 30, 2012 was primarily a result of our production increases from our well completions during the last two quarters of 2011 and the first two quarters of 2012. The DD&A rate for the six months ended June 30, 2012 was $24.04 per Boe compared to $18.61 per Boe for the six months ended June 30, 2011. The higher DD&A rate was due to a greater increase in well costs over an increase in reserves.

 

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Exploration expenses. The $2.5 million increase in exploration expenses to $2.8 million for the six months ended June 30, 2012 is primarily due to geological and geophysical costs for the purchase of 3D seismic data.

Impairment of oil and gas properties. During the six months ended June 30, 2012 and 2011, we recorded non-cash impairment charges of $2.6 million and $2.9 million, respectively, for unproved property leases that expired during the period or have been forecasted to expire under our current drilling plans. No impairment charges of proved oil and gas properties were recorded for the three months ended June 30, 2012 or 2011.

General and administrative expenses. Our general and administrative (“G&A”) expenses increased $13.2 million for the six months ended June 30, 2012 from $12.6 million for the six months ended June 30, 2011. Of this increase, approximately $9.9 million related to employee compensation expenses due to our organizational growth, including the addition of OWS, and $2.3 million was due to additional amortization of our restricted stock awards during the six months ended June 30, 2012. As of June 30, 2012, we had 223 full-time employees compared to 88 full-time employees as of June 30, 2011. Excluding G&A expenses related to OWS of $2.7 million, G&A related to E&P on a per Boe basis would have been $6.66 for the six months ended June 30, 2012.

Derivative instruments. As a result of our derivative activities, we incurred cash settlement net losses of $2.5 million and $4.7 million for the six months ended June 30, 2012 and 2011, respectively. In addition, as a result of forward oil price changes, we recognized a $58.5 million and a $0.5 million non-cash unrealized mark-to-market net derivative gain during the six months ended June 30, 2012 and 2011, respectively.

Interest expense. Interest expense increased $16.0 million to $28.0 million for the six months ended June 30, 2012 compared to the six months ended June 30, 2011. The increase was primarily the result of interest expense incurred on our senior unsecured notes issued in February and November 2011 at interest rates of 7.25% and 6.5%, respectively. There were no borrowings under our revolving credit facility during the six months ended June 30, 2012 and 2011, respectively.

Income taxes. Income tax expense for the six months ended June 30, 2012 and 2011 was recorded at 37.4% and 37.8% of pre-tax net income, respectively. Our effective tax rate is expected to continue to closely approximate the statutory rate applicable to the U.S. and the blended state rate of the states in which we conduct business.

Liquidity and Capital Resources

Our primary sources of liquidity as of the date of this report have been proceeds from our issuances of senior unsecured notes, proceeds from our IPO in June 2010, cash flows from operations and historically, borrowings under our revolving credit facility and capital contributions from private investors. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. We continually monitor potential capital sources, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

Our cash flows for the six months ended June 30, 2012 and 2011 are presented below:

 

     Six Months Ended
June 30,
 
     2012     2011  
     (In thousands)  

Net cash provided by operating activities

   $ 171,860      $ 102,095   

Net cash used in investing activities

     (401,894     (335,024

Net cash (used in) provided by financing activities

     (1,952     389,414   
  

 

 

   

 

 

 

(Decrease) increase in cash and cash equivalents

   $ (231,986   $ 156,485   
  

 

 

   

 

 

 

Cash flows provided by operating activities

Our cash flows depend on many factors, including the price of oil and natural gas and the success of our development and exploration activities as well as future acquisitions. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the change in oil prices on a portion of our production, thereby mitigating our exposure to oil price declines, but these transactions may also limit our cash flow in periods of rising oil prices.

Net cash provided by operating activities was $171.9 million and $102.1 million for the six months ended June 30, 2012 and 2011, respectively. The increase in cash flows provided by operating activities for the period ended June 30, 2012 as compared to 2011 was primarily the result of an increase in oil and natural gas production of 138%. In addition, at June 30, 2012, we had a working capital surplus of $87.6 million. This surplus was primarily attributable to our cash and cash equivalents balance as a result of the net proceeds from the issuance of our senior unsecured notes in 2011.

 

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Cash flows used in investing activities

Net cash used in investing activities was $401.9 million and $335.0 million during the six months ended June 30, 2012 and 2011, respectively. The increase in cash used in investing activities for the six months ended June 30, 2012 compared to 2011 of $66.9 million was mainly attributable to increased levels of capital expenditures for drilling and development costs.

Our capital expenditures for drilling, development and acquisition costs are summarized in the following table:

 

     Six Months Ended
June 30, 2012
 
     (In thousands)  

Project Area:

  

West Williston

   $ 391,975   

East Nesson

     106,617   

Sanish

     31,575   
  

 

 

 

Total E&P capital expenditures

     530,167   

Non-E&P capital expenditures (1)

     25,368   
  

 

 

 

Total capital expenditures (2)

   $ 555,535   
  

 

 

 

 

(1) Non-E&P capital expenditures include such items as equipment for OWS, district tools, administrative capital and capitalized interest.
(2) Capital expenditures reflected in the table above differ from the amounts shown in the statement of cash flows in our condensed consolidated financial statements because amounts reflected in the table above include accrued liabilities for capital expenditures, while the amounts presented in the statement of cash flows are presented on a cash basis.

On July 26, 2012, our Board of Directors increased our total 2012 capital expenditure budget from $884 million to $1,062 million, which now consists of:

 

   

$912 million of development capital for operated and non-operated wells (including expected savings from services provided by OWS);

 

   

$74 million for constructing infrastructure to support production in our core project areas, primarily related to SWD systems that will lower lease operating expenses;

 

   

$30 million for maintaining and expanding our leasehold position;

 

   

$6 million for micro-seismic work, purchase of seismic data and other test work;

 

   

$17 million for OWS, including $12 million for equipment budgeted and ordered in 2011 that arrived in the first quarter of 2012; and

 

   

$23 million for other non-E&P capital, including items such as district tools, administrative capital and capitalized interest.

The 2012 capital expenditure budget does not include approximately $30 million of capital that was related to 2011 activity that was included in the first quarter of 2012 actual capital expenditures. While we have budgeted $1,062 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses. We believe that cash on hand, cash flows from operating activities and availability under our revolving credit facility should be more than sufficient to fund our 2012 capital expenditure budget. However, because the operated wells funded by our 2012 drilling plan represent only a small percentage of our gross identified drilling locations, we will be required to generate or raise multiples of this amount of capital to develop our entire inventory of identified drilling locations should we elect to do so.

Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

 

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Cash flows used in or provided by financing activities

Net cash used in financing activities was $2.0 million for the six months ended June 30, 2012 compared to $389.4 million net cash provided by financing activities for the six months ended June 30, 2011. For the six months ended June 30, 2012, cash used in financing activities was primarily due to the purchases of treasury stock for shares withheld by the Company equivalent to the payroll tax withholding obligations due from employees upon the vesting of restricted stock awards combined with deferred financing costs related to the semi-annual redetermination of our borrowing base under our senior secured revolving line of credit. For the six months ended June 30, 2011, cash sourced through financing activities was primarily provided by the net proceeds from the issuance of our senior unsecured notes in February 2011.

Senior unsecured notes. On February 2, 2011, we issued $400 million of 7.25% senior unsecured notes due February 1, 2019 (the “2019 Notes”). Interest is payable on the 2019 Notes semi-annually in arrears on each February 1 and August 1, commencing August 1, 2011. The 2019 Notes are guaranteed on a senior unsecured basis by our material subsidiaries. The issuance of these 2019 Notes resulted in net proceeds to us of approximately $390 million, which we are using to fund our exploration, development and acquisition program and for general corporate purposes.