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Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

Form 10-Q

 

 

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

For the quarterly period ended September 30, 2011

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 1-32414

 

 

W&T OFFSHORE, INC.

(Exact name of registrant as specified in its charter)

 

 

 

Texas   72-1121985
(State of incorporation)  

(IRS Employer

Identification Number)

Nine Greenway Plaza, Suite 300

Houston, Texas

  77046-0908
(Address of principal executive offices)   (Zip Code)

(713) 626-8525

(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  þ    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    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   ¨    Accelerated filer   þ
Non-accelerated filer   ¨    Smaller reporting company   ¨

Indicate by check mark whether the registrant is a shell company.     Yes  ¨    No  þ

As of November 2, 2011, there were 74,461,440 shares outstanding of the registrant’s common stock, par value $0.00001.

 

 

 


Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

 

         Page  

PART I – FINANCIAL INFORMATION

  

Item 1.

  Financial Statements   
  Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010      1   
  Condensed Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2011 and 2010      2   
  Condensed Consolidated Statement of Changes in Shareholders’ Equity for the Nine Months Ended September 30, 2011      3   
  Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010      4   
  Notes to Condensed Consolidated Financial Statements      5   

Item 2.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     22   

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

     33   

Item 4.

 

Controls and Procedures

     34   

PART II – OTHER INFORMATION

  

Item 1.

  Legal Proceedings      34   

Item 1A.

  Risk Factors      34   

Item 5.

  Other      36   

Item 6.

  Exhibits      36   

SIGNATURE

     37   

EXHIBIT INDEX

     38   


Table of Contents

PART I – FINANCIAL INFORMATION

 

Item 1. Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

 

     September 30,
2011
    December 31,
2010
 
    

(In thousands, except share data)

(Unaudited)

 
Assets     

Current assets:

    

Cash and cash equivalents

   $ 7,666      $ 28,655   

Receivables:

    

Oil and natural gas sales

     82,824        79,911   

Joint interest and other

     18,199        25,415   

Insurance

     1,664        1,014   
  

 

 

   

 

 

 

Total receivables

     102,687        106,340   

Deferred income taxes

     —          5,784   

Prepaid expenses and other assets

     45,545        23,426   
  

 

 

   

 

 

 

Total current assets

     155,898        164,205   

Property and equipment – at cost:

    

Oil and natural gas properties and equipment (full cost method, of which $152,646 at September 30, 2011 and $65,419 at December 31, 2010 were excluded from amortization)

  

 

5,858,814

  

 

 

5,225,582

  

Furniture, fixtures and other

     16,158        15,841   
  

 

 

   

 

 

 

Total property and equipment

     5,874,972        5,241,423   

Less accumulated depreciation, depletion and amortization

     4,240,069        4,021,395   
  

 

 

   

 

 

 

Net property and equipment

     1,634,903        1,220,028   

Restricted deposits for asset retirement obligations

     34,675        30,636   

Deferred income taxes

     —          2,819   

Other assets

     15,723        6,406   
  

 

 

   

 

 

 

Total assets

   $ 1,841,199      $ 1,424,094   
  

 

 

   

 

 

 
Liabilities and Shareholders’ Equity     

Current liabilities:

    

Accounts payable

   $ 80,997      $ 80,442   

Undistributed oil and natural gas proceeds

     34,706        25,240   

Asset retirement obligations

     128,584        92,575   

Accrued liabilities

     30,294        25,827   

Income taxes payable

     1,657        17,552   

Income taxes deferred – current portion

     5,293        —     
  

 

 

   

 

 

 

Total current liabilities

     281,531        241,636   

Long-term debt

     694,000        450,000   

Asset retirement obligations, less current portion

     265,547        298,741   

Deferred income taxes

     45,438        —     

Other liabilities

     8,686        11,974   

Commitments and contingencies

     —          —     

Shareholders’ equity:

    

Preferred stock, $0.00001 par value; 2,000,000 shares authorized; 0 issued at September 30, 2011 and December 31, 2010

  

 

—  

  

 

 

—  

  

Common stock, $0.00001 par value; 118,330,000 shares authorized; 77,332,969 issued and 74,463,796 outstanding at September 30, 2011; 77,343,520 issued and 74,474,347 outstanding at December 31, 2010

  

 

1

  

 

 

1

  

Additional paid-in capital

     383,966        377,529   

Retained earnings

     186,197        68,380   

Treasury stock, at cost

     (24,167     (24,167
  

 

 

   

 

 

 

Total shareholders’ equity

     545,997        421,743   
  

 

 

   

 

 

 

Total liabilities and shareholders’ equity

   $ 1,841,199      $ 1,424,094   
  

 

 

   

 

 

 

See Notes to Condensed Consolidated Financial Statements.

 

1


Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2011     2010     2011     2010  
     (In thousands, except per share data)  
     (Unaudited)  

Revenues

   $   245,371      $   169,575      $   709,148      $   518,827   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating costs and expenses:

        

Lease operating expenses

     58,899        34,371        159,901        122,194   

Production taxes

     1,050        276        2,183        788   

Gathering and transportation

     4,853        4,607        13,203        12,920   

Depreciation, depletion and amortization

     77,056        69,051        218,674        201,870   

Asset retirement obligation accretion

     7,399        6,264        23,243        18,676   

General and administrative expenses

     18,104        13,389        54,235        38,143   

Derivative (gain) loss

     (17,323     4,770        (10,815     (8,500
  

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     150,038        132,728        460,624        386,091   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     95,333        36,847        248,524        132,736   

Interest expense:

        

Incurred

     14,721        10,485        36,913        32,319   

Capitalized

     (3,163     (1,345     (6,654     (4,090

Loss on extinguishment of debt

     2,031        —          22,694        —     

Interest income

     6        150        22        632   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before income tax expense

     81,750        27,857        195,593        105,139   

Income tax expense

     28,822        669        68,841        7,766   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 52,928      $ 27,188      $ 126,752      $ 97,373   
  

 

 

   

 

 

   

 

 

   

 

 

 

Basic and diluted earnings per common share

   $ 0.70      $ 0.36      $ 1.68      $ 1.30   

Dividends declared per common share

   $ 0.04      $ 0.04      $ 0.12      $ 0.10   

See Notes to Condensed Consolidated Financial Statements.

 

2


Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

 

     Common Stock
Outstanding
     Additional
Paid-In
Capital
     Retained
Earnings
    Treasury Stock     Total
Shareholders’
Equity
 
     Shares     Value           Shares      Value    
     (In thousands)  
     (Unaudited)  

Balances at December 31, 2010

     74,474      $ 1       $ 377,529       $ 68,380        2,869       $ (24,167   $ 421,743   

Cash dividends

     —          —           —           (8,935     —           —          (8,935

Share-based compensation

     —          —           6,437         —          —           —          6,437   

Restricted stock issued, net of forfeitures

     (10     —           —           —          —           —          —     

Net income

     —          —           —           126,752        —           —          126,752   
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Balances at September 30, 2011

     74,464      $ 1       $ 383,966       $ 186,197        2,869       $ (24,167   $ 545,997   
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

See Notes to Condensed Consolidated Financial Statements.

 

3


Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     Nine Months Ended September 30,  
     2011     2010  
     (In thousands)  
     (Unaudited)  

Operating activities:

    

Net income

   $ 126,752      $ 97,373   

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

    

Depreciation, depletion, amortization and accretion

     241,917        220,546   

Amortization of debt issuance costs

     1,401        1,004   

Loss on extinguishment of debt

     22,694        —     

Share-based compensation

     6,437        3,576   

Derivative (gain) loss

     (10,815     (8,500

Cash payments on derivative settlements

     (9,239     (410

Deferred income taxes

     59,442        6,483   

Changes in operating assets and liabilities:

    

Oil and natural gas receivables

     (2,913     3,630   

Joint interest and other receivables

     7,465        29,542   

Insurance receivables

     18,971        36,763   

Income taxes

     (15,894     84,152   

Prepaid expenses and other assets

     (22,601     (1,464

Asset retirement obligations

     (51,349     (62,620

Accounts payable and accrued liabilities

     23,892        (30,148

Other liabilities

     (109     12,950   
  

 

 

   

 

 

 

Net cash provided by operating activities

     396,051        392,877   
  

 

 

   

 

 

 

Investing activities:

    

Acquisitions of property interests in oil and natural gas properties

     (434,582     (116,589

Investment in oil and natural gas properties and equipment

     (185,222     (127,427

Proceeds from sales of oil and natural gas properties and equipment

     15        1,335   

Purchases of furniture, fixtures and other

     (318     (405
  

 

 

   

 

 

 

Net cash used in investing activities

     (620,107     (243,086
  

 

 

   

 

 

 

Financing activities:

    

Issuance of 8.5% Senior Notes

     600,000        —     

Repurchase of 8.25% Senior Notes

     (450,000     —     

Borrowings of long-term debt – revolving bank credit facility

     512,000        427,500   

Repayments of long-term debt – revolving bank credit facility

     (418,000     (427,500

Repurchase premium and debt issuance costs

     (31,997     —     

Dividends to shareholders

     (8,936     (7,467
  

 

 

   

 

 

 

Net cash provided (used) in financing activities

     203,067        (7,467
  

 

 

   

 

 

 

Increase (decrease) in cash and cash equivalents

     (20,989     142,324   

Cash and cash equivalents, beginning of period

     28,655        38,187   
  

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 7,666      $ 180,511   
  

 

 

   

 

 

 

See Notes to Condensed Consolidated Financial Statements.

 

4


Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Operations. W&T Offshore, Inc. and subsidiaries, referred to herein as “W&T” or the “Company,” is an independent oil and natural gas producer focused primarily in the Gulf of Mexico and onshore Texas. The Company is active in the acquisition, exploitation, exploration and development of oil and natural gas properties. W&T has recently diversified its operations by expanding onshore in Texas.

Interim Financial Statements. The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) for interim financial information and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the condensed consolidated financial statements do not include all of the information and footnote disclosures required by GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included.

Operating results for interim periods are not necessarily indicative of the results that may be expected for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

Reclassifications. Certain reclassifications have been made to the prior periods’ financial statements to conform to the current presentation.

Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

2. Acquisitions

On August 10, 2011, we completed the acquisition of Shell Offshore Inc.’s (“Shell”) 64.3% interest in the Fairway Field along with a like interest in the associated Yellowhammer gas processing plant (the “Fairway Properties”). The stated purchase price was $55.0 million, subject to certain adjustments, including adjustments from an effective date of September 1, 2010 until the closing date of August 10, 2011. Taking into account such adjustments, as of September 30, 2011, the cash purchase price component was $40.0 million. The decrease of $15.0 million primarily reflects net production cash flow, partially offset by plugging and abandonment costs incurred, from the effective date of September 1, 2010 to the closing date. The purchase price is subject to further post-effective date adjustments and final settlement is expected to occur in the first quarter of 2012. We assumed the asset retirement obligations (“ARO”) associated with the properties and plant which we have currently estimated to be $7.8 million. We are finalizing our assessment of the fair values of the assets acquired and liabilities assumed. Therefore, the purchase price allocation as described in the following table is preliminary and is subject to change. The acquisition was funded from borrowings under our revolving bank credit facility.

 

5


Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

The following table presents the preliminary purchase price allocation for the acquisition of the Fairway Properties (in thousands):

 

Oil and natural gas properties and equipment

   $     47,800   

Asset retirement obligations – non-current

     (7,812
  

 

 

 

Total cash paid

   $ 39,988   
  

 

 

 

On May 11, 2011, we completed the acquisition of approximately 21,900 gross acres (21,500 net acres) of oil and gas leasehold interests in the West Texas Permian Basin (the “Permian Basin Properties”) from Opal Resources LLC and Opal Resources Operating Company LLC (“Opal”). The stated purchase price was $366.3 million, subject to certain adjustments, including adjustments from an effective date of January 1, 2011 until the closing date of May 11, 2011. Taking into account such adjustments, as of September 30, 2011, the purchase price was $397.1 million. The increase of $30.8 million primarily reflects drilling costs in excess of cash flow from the effective date of January 1, 2011 to the closing date. Although further adjustments could occur to the purchase price, no further adjustments are expected at this time. The acquisition was funded from cash on hand and borrowings under our revolving bank credit facility.

The following table presents the purchase price allocation for the acquisition of the Permian Basin Properties (in thousands):

 

Oil and natural gas properties and equipment (1)

   $     397,119   

Asset retirement obligations – non-current

     (382

Long-term liability

     (2,143
  

 

 

 

Total cash paid

   $ 394,594   
  

 

 

 

 

(1) As of September 30, 2011, $82.6 million has been recorded as unproved properties which are excluded from the full cost pool and amortization base.

For the three months ended September 30, 2011, the Permian Basin Properties and the Fairway Properties accounted for $21.6 million of revenue, $8.8 million of direct operating expenses, $7.2 million of depreciation, depletion, amortization and accretion (“DD&A”) and $2.0 million of income taxes, resulting in $3.6 million of net income. For the nine months ended September 30, 2011, the Permian Basin Properties and the Fairway Properties accounted for $32.8 million of revenue, $10.7 million of direct operating expenses, $9.6 million of DD&A and $4.4 million of income taxes, resulting in $8.1 million of net income. Such amounts are for the period from each respective close date to September 30, 2011. The net income attributable to these properties does not reflect certain expenses, such as general and administrative expenses and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. In addition, the Permian Basin Properties and the Fairway Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate. Expenses associated with acquisition activities and transition activities related to these acquisitions for the three and nine months ended September 30, 2011 were $0.8 million and $1.4 million, respectively, and are included in general and administrative expenses.

Pro forma financial statements have been prepared due to the Permian Basin Properties being significant. The Fairway Properties acquisition, which was not significant, was combined with the Permian Basin Properties to disclose the effect of both acquisitions. The unaudited pro forma financial information was computed as if these two acquisitions had been completed on January 1, 2010. The historical financial information is derived from the unaudited historical consolidated financial statements of W&T and the unaudited historical statements of the sellers.

The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Permian Basin Properties and the Fairway Properties. The pro forma financial information is not

 

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Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

necessarily indicative of the results of operations had the purchase occurred on January 1, 2010. If the transactions had been in effect for the periods indicated, the results may have been substantially different. For example, we may have operated the assets differently than the sellers, realized sales prices may have been different and costs of operating the properties may have been different. The following table presents a summary of our pro forma condensed combined statements of income for the nine months ended September 30, 2011 and 2010 (in thousands except earnings per share):

 

     Three Months Ended,
September 30,
     Nine Months Ended,
September 30,
 
     2011      2010      2011      2010  

Revenue

   $   250,257       $   187,163       $   761,531       $   574,820   

Net income

     56,207         25,449         139,134         95,467   

Basic and diluted earnings per common share

     0.74         0.34         1.84         1.28   

The purchase price of both acquisitions may be subject to further adjustments. For these pro forma financial statements, we assumed the transactions were financed with borrowings from the revolving bank credit facility because the cash and cash equivalents balances for the assumed acquisition date was less than the cash and cash equivalents on hand used on the actual closing dates of the two acquisitions. Also, we assumed that the revolving bank credit facility capacity would have been increased due to the increase in reserves.

The following adjustments were made in the preparation of the condensed combined statement of income:

 

  (a) Revenues and direct operating expenses for the Permian Basin Properties and the Fairway Properties were derived from the historical records of the sellers up to the respective closing dates.

 

  (b) DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Permian Basin Properties and Fairway Properties costs, reserves and production into the computation. The purchase price allocation included $82.6 million allocated to the pool of unevaluated properties for oil and gas interests. Accordingly, no DD&A expense was estimated for the unevaluated properties.

 

  (c) Asset retirement obligations and related accretion were estimated by W&T management.

 

  (d) Incremental transaction expenses related to the acquisitions for the three and nine months ended September 30, 2011 were $0.8 million and $1.4 million, respectively, and were assumed to be funded from cash on hand.

 

  (e) Interest expense was computed using interest rates that were in effect during the applicable time period and we assumed that six-month LIBOR borrowings were made as allowed under the revolving bank credit facility. The assumed interest rates ranged from 3.1% to 3.5%. A reduction in the revolving bank credit facility commitment fee related to the assumed borrowings was netted against the computed incremental interest expense.

 

  (f) Incremental capitalized interest was computed for the addition to the pool of unevaluated properties and the capitalization interest rate was adjusted for the assumed borrowings.

 

  (g) Income tax was computed using the 35% federal statutory rate.

During 2010, we closed on two acquisition transactions. The first closed on April 30, 2010. Through our wholly-owned subsidiary, W&T Energy VI, LLC (“Energy VI”), we acquired all of Total E&P USA’s (“Total”) interest, including production platforms and facilities, in three federal offshore lease blocks located in the Gulf of Mexico and assumed the asset retirement obligations (“ARO”) for plugging and abandonment of the acquired interests. The adjusted purchase price was $121.3 million. The properties acquired from Total (the “Matterhorn/Virgo Properties”) are producing interests and include a 100% working interest in the Matterhorn field (Mississippi Canyon block 243) and a 64% working interest in the Virgo field (Viosca Knoll blocks 822 and 823). The second closed on November 4, 2010. Through Energy VI,

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

we acquired all of Shell’s interests, including production platforms and facilities, in three federal offshore lease blocks located in the Gulf of Mexico and assumed the ARO for plugging and abandonment of the acquired interests. The adjusted purchase price was $134.2 million. The properties acquired from Shell (the “Tahoe/Droshky Properties”) are producing interests and include a 70% working interest in the Tahoe field (Viosca Knoll 783), 100% working interest in the Southeast Tahoe field (Viosca Knoll 784) and a 6.25% of 8/8ths overriding royalty interest in the Droshky field (Green Canyon 244).

3. Hurricane Remediation and Insurance Claims

During the third quarter of 2008, Hurricane Ike and, to a much lesser extent, Hurricane Gustav caused property damage and disruptions to our exploration and production activities. Our insurance policies in effect on the occurrence dates of Hurricanes Ike and Gustav had a retention requirement of $10 million per occurrence to be satisfied by us before we could be indemnified for losses. In the fourth quarter of 2008, we satisfied our $10 million retention requirement for Hurricane Ike in connection with two platforms that were toppled and were deemed total losses. Our insurance coverage policy limits at the time of Hurricane Ike were $150 million for property damage due to named windstorms (excluding certain damage incurred at our facilities of marginal significance) and $250 million for, among other things, removal of wreckage if mandated by any governmental authority. The damage we incurred as a result of Hurricane Gustav was below our retention amount.

Below is a summary of remediation costs and amounts approved for payments related to Hurricanes Ike and Gustav that were included in lease operating expense (in thousands), with bracketed amounts representing credits to expense:

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2011     2010     2011     2010  

Incurred and reversals of accruals

   $ (4   $ 413      $ 71      $ (1,465

Plus amounts returned to insurers

     —          —          1,241        —     

Less amounts approved for payment by insurers

     (537     (7,522     (1,124     (9,879
  

 

 

   

 

 

   

 

 

   

 

 

 

Included in lease operating expense

   $ (541   $ (7,109   $ 188      $ (11,344
  

 

 

   

 

 

   

 

 

   

 

 

 

We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when we deem those to be probable of collection, which arises when our insurance underwriters’ adjuster reviews and approves such costs for payment by the underwriters. Claims that have been processed in this manner have customarily been paid on a timely basis. Incurred expenses included revisions of previous estimates. Amounts in 2011 include return of reimbursements that were previously received by us related to prepayments based on preliminary estimates. See Note 4 for additional information about the impact of hurricane related items on our asset retirement obligations.

Below is a reconciliation of our insurance receivables from December 31, 2010 to September 30, 2011 (in thousands):

 

Balance, December 31, 2010

   $ 1,014   

Costs approved under our insurance policies, net

     19,506   

Payments received, net

     (18,856
  

 

 

 

Balance, September 30, 2011

   $ 1,664   
  

 

 

 

At September 30, 2011 and December 31, 2010, substantially all of the amounts in insurance receivables relate to the plugging and abandonment of wells and dismantlement of facilities damaged by Hurricane Ike. We expect that our available cash and cash equivalents, cash flow from operations and the availability under our revolving bank credit facility will be sufficient to meet necessary expenditures that may exceed our insurance coverage for damages incurred as a result of Hurricane Ike.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

4. Asset Retirement Obligations

Our asset retirement obligations primarily represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. A summary of the changes to our asset retirement obligations is as follows (in thousands):

 

Balance, December 31, 2010

   $   391,316   

Liabilities settled

     (51,349

Accretion of discount

     23,243   

Liabilities assumed through acquisition

     8,194   

Liabilities incurred

     451   

Revisions of estimated liabilities due to Hurricane Ike

     4,763   

Revisions of estimated liabilities – all other

     17,513   
  

 

 

 

Balance, September 30, 2011

     394,131   

Less current portion

     128,584   
  

 

 

 

Long-term

   $ 265,547   
  

 

 

 

5. Derivative Financial Instruments

Our market risk exposure relates primarily to commodity prices and interest rates. From time to time, we use various derivative instruments to manage our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility. We do not enter into derivative instruments for speculative trading purposes. Our derivative instruments currently consist of commodity option contracts. We are exposed to credit loss in the event of nonperformance by the counterparties; however, we do not currently anticipate any of our counterparties being unable to fulfill their contractual obligations.

We account for derivative contracts in accordance with GAAP, which requires each derivative to be recorded on the balance sheet as an asset or a liability at its fair value. Changes in a derivative’s fair value are required to be recognized currently in earnings unless specific hedge accounting criteria are met at the time we enter into a derivative contract. We have elected not to designate our commodity derivatives as hedging instruments. For additional information about fair value measurements, refer to Note 7.

Commodity Derivative: During 2010, we entered into commodity option contracts to manage a portion of our exposure to commodity price risk from sales of oil through December 31, 2012. While these contracts are intended to reduce the effects of price volatility, they may also limit future income from favorable price movements. As of September 30, 2011, our open commodity derivatives were as follows:

 

Zero Cost Collars – Oil

 

Effective

Date

   Termination
Date
     Notional
Quantity  (Bbls)
     Weighted Average
NYMEX Contract Price
     Fair Value
Asset
(in thousands)
 
         Floor      Ceiling     
              

10/1/2011

     12/31/2011         392,100       $   75.00       $   95.58       $ 1,053   

1/1/2012

     3/31/2012         364,000         75.00         97.88         1,449   

4/1/2012

     6/30/2012         364,000         75.00         97.88         1,390   

7/1/2012

     9/30/2012         124,000         75.00         97.88         444   

10/1/2012

     12/31/2012         251,000         75.00         98.99         836   
     

 

 

    

 

 

    

 

 

    

 

 

 
        1,495,100       $   75.00       $   97.46       $ 5,172   
     

 

 

    

 

 

    

 

 

    

 

 

 

At September 30, 2011, $4.4 million and $0.8 million were included in current assets and other long-term assets, respectively, related to our commodity derivative contracts. At December 31, 2010, $9.5 million and $5.4 million were included in accrued liabilities and other long-term liabilities, respectively, related to our commodity derivative contracts. Our

 

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(Unaudited)

 

derivative gain for the three months ended September 30, 2011 includes realized losses of $0.9 million and unrealized gains of $18.2 million related to our commodity derivatives. Our derivative gain for the nine months ended September 30, 2011 includes realized losses of $9.2 million and unrealized gains of $20.0 million related to our commodity derivatives. Our derivative loss for the three months ended September 30, 2010 includes a realized gain of $1.1 million and an unrealized loss of $5.9 million related to our commodity derivatives. Our derivative gain for the nine months ended September 30, 2010 includes realized and unrealized gains of $4.3 million and $4.5 million, respectively, related to our commodity derivatives.

Interest Rate Swap: Our interest rate swap contract with a fixed interest rate of 5.21% expired in August 2010. During the three months ended September 30, 2010, we recognized an unrealized gain of $1.0 million and a realized loss of $1.0 million for this contract. During the nine months ended September 30, 2010, we recognized an unrealized gain of $4.4 million and a realized loss of $4.7 million for this contract.

6. Long-Term Debt

On June 10, 2011, we issued $600 million of our senior notes at par with an interest rate of 8.5% and maturity date of June 15, 2019 (the “8.5% Senior Notes”). Interest is payable semi-annually in arrears on June 15 and December 15 of each year beginning on December 15, 2011. The 8.5% Senior Notes are unsecured and are fully and unconditionally guaranteed by certain of our subsidiaries. The restrictive covenants and redemption provisions of the 8.5% Senior Notes are substantially similar to the terms of the 8.25% Senior Notes due 2014 (the “8.25% Senior Notes”). At September 30, 2011, the outstanding balance of our 8.5% Senior Notes was $600 million and was classified at their carrying value as long-term debt. The estimated annual effective interest rate on the 8.5% Senior Notes is 8.7% which includes amortization of debt issuance costs. At September 30, 2011, the estimated fair value of the 8.5% Senior Notes was approximately $579 million. For additional details about fair value measurements, refer to Note 7.

In June and July of 2011, we used a portion of the net proceeds from the issuance of the 8.5% Senior Notes to repurchase all of our 8.25% Senior Notes, which had a principal amount of $450 million. Costs of $22.0 million related to repurchasing the 8.25% Senior Notes, which included repurchase premiums and the unamortized debt issuance costs, are included in the statement of income within the line item classification, Loss on extinguishment of debt. At December 31, 2010, the outstanding balance of our 8.25% Senior Notes was $450 million and was classified at their carrying value as long-term debt. At December 31, 2010, the estimated fair value of the 8.25% Senior Notes was approximately $441 million. For additional details about fair value measurements, refer to Note 7.

On May 5, 2011, we entered into a Fourth Amended and Restated Credit Agreement (the “Credit Agreement”) which provides a revolving bank credit facility with an initial borrowing base of $525 million. This is a secured facility that is collateralized by our oil and natural gas properties. The Credit Agreement terminates on May 5, 2015 and replaces the prior Third Amended and Restated Credit Agreement (the “Prior Credit Agreement”), which would have expired July 23, 2012. The pricing terms and restrictive covenants of the Credit Agreement are substantially similar to the terms of the Prior Credit Agreement. Availability under the Credit Agreement is subject to a semi-annual borrowing base determination set at the discretion of our lenders. The amount of the borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. Any determination by our lenders to change our borrowing base will result in a similar change in the availability under our revolving bank credit facility.

Pursuant to the Credit Agreement, the initial borrowing base was adjusted due to the following two items. First, the initial borrowing base was reduced by $37.5 million due to the issuance of the 8.5% Senior Notes of $600 million. Second, the borrowing base was increased by $50 million due to the consummation of the acquisition of the Fairway Properties in August 2011. After these two transactions, our borrowing base was $537.5 million as of September 30, 2011. In October 2011, the borrowing base was re-determined by our lenders and increased to $575 million.

The Credit Agreement contains covenants that restrict, among other things, the payment of cash dividends and share repurchases of up to $60 million per year, borrowings other than from the revolving bank credit facility, sales of assets, loans to others, investments, merger activity, hedging contracts, liens and certain other transactions without the prior consent of the lenders. Letters of credit may be issued up to $90 million, provided availability under the revolving bank credit facility

 

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(Unaudited)

 

exists. We are subject to various financial covenants calculated as of the last day of each fiscal quarter including a minimum current ratio and a maximum leverage ratio as such ratios are defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement as of September 30, 2011.

Borrowings under the revolving bank credit facility bear interest at the applicable London Interbank Offered Rate (“LIBOR”) plus a margin that varies from 2.00% to 2.75% depending on the level of total borrowings under the Credit Agreement, or an alternative base rate equal to the applicable margin ranging from 1.00% to 1.75% plus the highest of the (a) Prime Rate, (b) Federal Funds Rate plus 0.50%, and (c) LIBOR plus 1.0%. The unused portion of the borrowing base is subject to a commitment fee of 0.50%. The estimated annual effective interest rate was 3.7% for the nine months ended September 30, 2011 for borrowings under the Credit Agreement and the Prior Credit Agreement and includes amortization of debt issuance costs, and excludes commitment fees and other costs.

Unamortized debt issuance costs of $0.7 million related to the Prior Credit Agreement were written off and are included in the statement of income within the line item classification, Loss on extinguishment of debt.

At September 30, 2011, we had $94 million in borrowings and $0.5 million in letters of credit outstanding under the revolving bank credit facility. At December 31, 2010, we had no borrowings and $0.4 million in letters of credit outstanding under the revolving bank credit facility provided by the Prior Credit Agreement.

7. Fair Value Measurements

We measure the fair value of our derivative financial instruments by applying the income approach, using models with inputs that are classified within Level 2 of the valuation hierarchy. The inputs used for the fair value measurement of our derivative financial instruments are the exercise price, the expiration date, the settlement date, notional quantities, the implied volatility, the discount curve with spreads and published commodity futures prices. As described in Note 5, our derivative financial instruments are reported in the balance sheet at fair value and changes in fair value are recognized currently in earnings.

The fair value of our senior notes is based on quoted prices. The market for our senior notes is not an active market; therefore the fair value is classified within Level 2. The senior notes are reported in the balance sheet at their carrying value and their fair value is reported in Note 6.

8. Share-Based Compensation and Cash-Based Incentive Compensation

In 2010, the W&T Offshore, Inc. Amended and Restated Incentive Compensation Plan (the “Plan”) was approved by our shareholders. As allowed by the Plan, in August 2010 and August 2011, the Company granted restricted stock units (“RSUs”) to certain of its employees and in January 2011, the Company granted restricted stock to one of its employees. RSUs are a long-term compensation component of the Plan, which are granted to only certain employees, and are subject to adjustments at the end of the applicable performance period based on the Company achieving certain predetermined performance criteria. The RSUs vest at the end of a specified deferral period. Prior to 2010, the Company granted only restricted stock to its employees. In 2011 and in prior years, restricted stock was granted to the Company’s non-employee directors under the Director Compensation Plan. In addition to share-based compensation, the Company may grant its employees cash-based incentive awards, which are a short-term component of the Plan, and are based on the Company and the employee achieving certain predetermined performance criteria.

We recognize compensation cost for share-based payments to employees and non-employee directors over the period during which the recipient is required to provide service in exchange for the award, based on the fair value of the equity instrument on the date of grant. We are also required to estimate forfeitures, resulting in the recognition of compensation cost only for those awards that actually vest.

At September 30, 2011, there were 2,157,482 shares of common stock available for award under the Plan and 568,783 shares of common stock available for award under the Directors Compensation Plan.

 

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(Unaudited)

 

Restricted Stock: The Company currently has unvested restricted shares outstanding issued to employees and non-employee directors. Restricted shares are subject to forfeiture until vested and cannot be sold, transferred or disposed of during the restricted period. The holders of restricted shares generally have the same rights as a shareholder of the Company with respect to such shares, including the right to vote and receive dividends or other distributions paid with respect to the shares.

A summary of share activity related to restricted stock for the nine months ended September 30, 2011 is as follows:

 

     Restricted Stock  
     Shares     Weighted Average
Grant Date Fair
Value Per Share
 

Outstanding restricted shares, December 31, 2010

     470,392      $ 7.42   

Granted

     20,433        25.45   

Vested

     (24,633     13.26   

Forfeited

     (30,984     6.83   
  

 

 

   

Outstanding restricted shares, September 30, 2011

     435,208        7.98   
  

 

 

   

At September 30, 2011, the composition of our restricted stock awards outstanding, by year granted, was as follows:

 

     Shares  

Employees – granted in:

  

2011

     5,325  (1) 

2009

     380,675  (2) 

Non-employee directors – granted in:

  

2011

     15,108  (3) 

2010

     23,330  (4) 

2009

     10,770  (5) 
  

 

 

 

Total

     435,208   
  

 

 

 

 

Vesting is expected to occur, less any forfeitures, as follows:

 

(1) Equal installments in December 2011 and December 2012.
(2) December 2011.
(3) Equal installments in May 2012, 2013 and 2014.
(4) Equal installments in May 2012 and 2013.
(5) May 2012.

The grant date fair value of restricted stock granted during the nine months ended September 30, 2011 and 2010 was $0.5 million and $0.4 million, respectively. The fair value of the shares that vested during the nine months ended September 30, 2011 and 2010 was $0.6 million and $0.1 million, respectively.

Restricted Stock Units: During 2011, the Company awarded to certain employees RSUs that are 100% contingent upon meeting a specified performance requirement for the year 2011. If the performance requirement is achieved, the RSUs awarded in 2011 will earn dividend equivalents effective January 1, 2012 at the same rate as dividends paid on our common stock. During 2010, the Company awarded to certain employees RSUs that were 100% contingent upon meeting a specified performance requirement, which was achieved in 2010. Effective January 2011, RSUs awarded in 2010 earn dividend equivalents at the same rate as dividends paid on our common stock. RSUs awarded in both years are subject to forfeiture until vested and cannot be sold, transferred or disposed of during the restricted period.

 

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A summary of share activity related to RSUs for the nine months ended September 30, 2011 is as follows:

 

     Restricted Stock Units  
     Units     Weighted Average
Grant Date Fair

Value Per Unit
 
    

Outstanding RSUs, December 31, 2010

     1,266,617      $ 9.36   

Granted

     528,042        26.93   

Vested

     —          —     

Forfeited

     (65,660     11.44   
  

 

 

   

Outstanding RSUs, September 30, 2011 (1)

     1,728,999        14.65   
  

 

 

   

 

(1) Subject to employment conditions, 1,208,714 and 520,285 RSU’s will vest in December 2012 and December 2013, respectively.

During the nine months ended September 30, 2011 and 2010, the fair value of RSUs granted was $14.2 million and $12.0 million, respectively. No vesting of RSUs occurred in either time period.

Share-Based Compensation: A summary of incentive compensation expense under share-based payment arrangements and the related tax benefit for the three and nine months ended September 30, 2011 and 2010 is as follows (in thousands):

 

     Three Months  Ended
September 30,
     Nine Months  Ended
September 30,
 
     2011      2010      2011      2010  

Share-based compensation expense from:

           

Restricted stock

   $ 593       $ 807       $ 1,784       $ 2,750   

Restricted stock units

     2,182         826         4,653         826   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 2,775       $ 1,633       $ 6,437       $ 3,576   
  

 

 

    

 

 

    

 

 

    

 

 

 

Share-based compensation tax benefit:

           

Tax benefit computed at the statutory rate

   $ 971       $ 572       $ 2,253       $ 1,252   
  

 

 

    

 

 

    

 

 

    

 

 

 

Cash-based Incentive Compensation: As defined by the Plan, annual cash-based incentive awards may be granted to eligible employees. These awards are performance-based awards consisting of one or more business criteria and individual performance criteria and a targeted level or levels of performance with respect to each of such criteria. Generally, the performance period is the calendar year and determination and payment is made in cash in the first quarter of the following year.

 

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Incentive Compensation: A summary of incentive compensation expense for the three and nine months ended September 30, 2011 and 2010 is as follows (in thousands):

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
         2011              2010              2011              2010      

Share-based compensation expense included in:

           

Lease operating expense

   $ 116       $ 171       $ 349       $ 599   

General and administrative

     2,659         1,462         6,088         2,977   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total charged to operating income

     2,775         1,633         6,437         3,576   
  

 

 

    

 

 

    

 

 

    

 

 

 

Cash-based incentive compensation included in:

           

Lease operating expense

     697         507         2,836         1,284   

General and administrative

     3,024         2,564         9,175         5,475   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total charged to operating income

     3,721         3,071         12,011         6,759   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total incentive compensation charged to operating income

   $ 6,496       $ 4,704       $ 18,448       $ 10,335   
  

 

 

    

 

 

    

 

 

    

 

 

 

As of September 30, 2011, unrecognized share-based compensation expense related to our outstanding restricted shares and RSUs was $1.1 million and $18.2 million, respectively. Unrecognized compensation expense will be recognized through April 2014 for restricted shares and November 2013 for RSUs.

9. Income Taxes

Income tax expense of $28.8 million and $68.8 million was recorded during the three and nine months ended September 30, 2011, respectively. Our effective tax rate for the three and nine months ended September 30, 2011 was 35.3% and 35.2%, respectively, which approximated the federal and state statutory rates. Income tax expense of $0.7 million and $7.8 million was recorded during the three and nine months ended September 30, 2010, respectively. Our effective tax rate for the three and nine months ended September 30, 2010 was 2.4% and 7.4%, respectively, and primarily reflects a reduction in our valuation allowance that was recorded in prior years.

Exclusive of interest, the amount of unrecognized tax benefit recorded in other liabilities as of September 30, 2011 and December 31, 2010 was $ 3.3 million and $3.6 million, respectively. We recognize interest and penalties related to unrecognized tax benefits in income tax expense and these amounts were immaterial for the nine months ended September 30, 2011 and 2010. The tax years from 2008 through 2010 remain open to examination by the applicable tax jurisdictions.

10. Earnings Per Share

The following table presents the calculation of basic earnings per common share for the three and nine months ended September 30, 2011 and 2010 (in thousands, except per share amounts):

 

     Three Months Ended
September 30,
     Nine Months Ended
September 30,
 
     2011      2010      2011      2010  

Net income

   $   52,928       $   27,188       $   126,752       $   97,373   

Less portion allocated to nonvested shares

     1,118         351         2,680         1,304   
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income allocated to common shares

   $ 51,810       $ 26,837       $ 124,072       $ 96,069   
  

 

 

    

 

 

    

 

 

    

 

 

 

Weighted average common shares outstanding

     74,028         73,675         74,017         73,668   
  

 

 

    

 

 

    

 

 

    

 

 

 

Basic and diluted earnings per common share

   $ 0.70       $ 0.36       $ 1.68       $ 1.30   

Shares excluded due to being anti-dilutive (weighted-average)

     1,995         1,787         1,798         1,310   

 

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11. Dividends

During the nine months ended September 30, 2011, we paid regular cash dividends of $0.04 per common share per quarter. During the nine months ended September 30, 2010, we paid regular cash dividends of $0.04, $0.03 and $0.03 per common share per quarter, respectively. On October 31, 2011, our board of directors declared a cash dividend of $0.04 per common share, payable on December 1, 2011 to shareholders of record on November 16, 2011.

12. Contingencies

The United States Attorney’s Office for the Eastern District of Louisiana, along with the Criminal Investigation Division of the Environmental Protection Agency, is conducting a federal grand jury investigation of environmental compliance matters relating to surface discharges and reporting on four of our offshore platforms in the Gulf of Mexico. We are fully cooperating with the investigation. The United States Attorney’s Office has recently informed us that they are continuing with their investigation with the intent to seek a criminal disposition. We are not able at this time to estimate our potential exposure, if any, related to this matter.

We are a party to various pending or threatened claims and complaints seeking damages or other remedies concerning our commercial operations and other matters in the ordinary course of our business. In addition, claims or contingencies may arise related to matters occurring prior to our acquisition of properties or related to matters occurring subsequent to our sale of properties. In certain cases, we have indemnified the sellers of properties we have acquired, and in other cases, we have indemnified the buyers of properties we have sold. We are also subject to federal and state administrative proceedings conducted in the ordinary course of business. Although we can give no assurance about the outcome of pending legal and federal or state administrative proceedings and the effect such an outcome may have on us, management believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

 

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(Unaudited)

 

13. Supplemental Guarantor Information

Our payment obligations under the 8.5% Senior Notes and the Credit Agreement (see Note 6) are fully and unconditionally guaranteed by certain of our wholly-owned subsidiaries, Energy VI, which includes the operations of acquisitions closed in 2010 as described in Note 2, and W&T Energy VII, LLC which does not have any active operations, (together, the “Guarantor Subsidiaries”).

The following unaudited condensed consolidating financial information presents the financial condition, results of operations and cash flows of W&T Offshore, Inc. and other consolidated subsidiaries (“Parent Company”) and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis. Consolidated subsidiaries other than the Guarantor Subsidiaries are considered “minor” under applicable accounting rules of the SEC.

Condensed Consolidating Balance Sheet as of September 30, 2011

 

     Parent
Company
    Guarantor
Subsidiaries
     Eliminations     Consolidated
W&T
Offshore, Inc.
 
         
         
     (In thousands)  
Assets          

Current assets:

         

Cash and cash equivalents

   $ 7,666      $ —         $ —        $ 7,666   

Receivables:

         

Oil and natural gas sales

     61,368        21,456         —          82,824   

Joint interest and other

     18,199        —           —          18,199   

Insurance

     1,664        —           —          1,664   

Income taxes

     62,592        —           (62,592     —     
  

 

 

   

 

 

    

 

 

   

 

 

 

Total receivables

     143,823        21,456         (62,592     102,687   

Prepaid expenses and other assets

     45,545        —           —          45,545   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total current assets

     197,034        21,456         (62,592     155,898   

Property and equipment – at cost:

         

Oil and natural gas properties and equipment

     5,587,206        271,608         —          5,858,814   

Furniture, fixtures and other

     16,158        —           —          16,158   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total property and equipment

     5,603,364        271,608         —          5,874,972   

Less accumulated depreciation, depletion and amortization

     4,149,960        90,109         —          4,240,069   
  

 

 

   

 

 

    

 

 

   

 

 

 

Net property and equipment

     1,453,404        181,499         —          1,634,903   

Restricted deposits for asset retirement obligations

     34,675        —           —          34,675   

Deferred income tax

     —          11,662         (11,662     —     

Other assets

     345,143        212,655         (542,075     15,723   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total assets

   $ 2,030,256      $ 427,272       $ (616,329   $ 1,841,199   
  

 

 

   

 

 

    

 

 

   

 

 

 
Liabilities and Shareholders’ Equity          

Current liabilities:

         

Accounts payable

   $ 79,587      $ 1,410       $ —        $ 80,997   

Undistributed oil and natural gas proceeds

     34,355        351         —          34,706   

Asset retirement obligations

     128,584        —           —          128,584   

Accrued liabilities

     30,294        —           —          30,294   

Income taxes

     —          64,249         (62,592     1,657   

Deferred income taxes – current portion

     5,293        —           —          5,293   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total current liabilities

     278,113        66,010         (62,592     281,531   

Long-term debt

     694,000        —           —          694,000   

Asset retirement obligations, less current portion

     233,704        31,843         —          265,547   

Deferred income taxes

     57,100        —           (11,662     45,438   

Other liabilities

     221,342        —           (212,656     8,686   

Commitments and contingencies

     —          —           —          —     

Shareholders’ equity:

         

Common stock

     1        —           —          1   

Additional paid-in capital

     383,966        231,759         (231,759     383,966   

Retained earnings

     186,197        97,660         (97,660     186,197   

Treasury stock, at cost

     (24,167     —           —          (24,167
  

 

 

   

 

 

    

 

 

   

 

 

 

Total shareholders’ equity

     545,997        329,419         (329,419     545,997   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total liabilities and shareholders’ equity

   $ 2,030,256      $ 427,272       $ (616,329   $ 1,841,199   
  

 

 

   

 

 

    

 

 

   

 

 

 

 

16


Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Condensed Consolidating Balance Sheet as of December 31, 2010

 

     Parent
Company
    Guarantor
Subsidiaries
     Eliminations     Consolidated
W&T
Offshore, Inc.
 
     (In thousands)  
Assets          

Current assets:

         

Cash and cash equivalents

   $ 28,655      $ —         $ —        $ 28,655   

Receivables:

         

Oil and natural gas sales

     50,421        29,490         —          79,911   

Joint interest and other

     25,415        —           —          25,415   

Insurance

     1,014        —           —          1,014   

Income taxes

     2,492        —           (2,492     —     
  

 

 

   

 

 

    

 

 

   

 

 

 

Total receivables

     79,342        29,490         (2,492     106,340   

Deferred income taxes

     5,784        2,755         (2,755     5,784   

Prepaid expenses and other assets

     23,426        —           —          23,426   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total current assets

     137,207        32,245         (5,247     164,205   

Property and equipment – at cost:

         

Oil and natural gas properties and equipment

     4,955,460        270,122         —          5,225,582   

Furniture, fixtures and other

     15,841        —           —          15,841   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total property and equipment

     4,971,301        270,122         —          5,241,423   

Less accumulated depreciation, depletion and amortization

     3,994,085        27,310         —          4,021,395   
  

 

 

   

 

 

    

 

 

   

 

 

 

Net property and equipment

     977,216        242,812         —          1,220,028   

Restricted deposits for asset retirement obligations

     30,636        —           —          30,636   

Deferred income taxes

     2,819        —           —          2,819   

Other assets

     275,461        47,160         (316,215     6,406   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total assets

   $ 1,423,339      $ 322,217       $ (321,462   $ 1,424,094   
  

 

 

   

 

 

    

 

 

   

 

 

 
Liabilities and Shareholders’ Equity          

Current liabilities:

         

Accounts payable

   $ 77,422      $ 3,020       $ —        $ 80,442   

Undistributed oil and natural gas proceeds

     24,866        374         —          25,240   

Asset retirement obligations

     92,575        —           —          92,575   

Accrued liabilities

     25,827        —           —          25,827   

Income taxes

     —          20,044         (2,492     17,552   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total current liabilities

     220,690        23,438         (2,492     241,636   

Long-term debt

     450,000        —           —          450,000   

Asset retirement obligations, less current portion

     269,016        29,725         —          298,741   

Deferred income taxes

     2,755        —           (2,755     —     

Other liabilities

     59,135        —           (47,161     11,974   

Commitments and contingencies

     —          —           —          —     

Shareholders’ equity:

         

Common stock

     1        —           —          1   

Additional paid-in capital

     377,529        236,944         (236,944     377,529   

Retained earnings

     68,380        32,110         (32,110     68,380   

Treasury stock, at cost

     (24,167     —           —          (24,167
  

 

 

   

 

 

    

 

 

   

 

 

 

Total shareholders’ equity

     421,743        269,054         (269,054     421,743   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total liabilities and shareholders’ equity

   $ 1,423,339      $ 322,217       $ (321,462   $ 1,424,094   
  

 

 

   

 

 

    

 

 

   

 

 

 

 

17


Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Condensed Consolidating Statement of Income for the Three Months Ended September 30, 2011

 

     Parent
Company
    Guarantor
Subsidiaries
     Eliminations     Consolidated
W&T
Offshore, Inc.
 
     (In thousands)  

Revenues

   $ 174,935      $ 70,436       $ —        $ 245,371   
  

 

 

   

 

 

    

 

 

   

 

 

 

Operating costs and expenses:

         

Lease operating expenses

     49,854        9,045         —          58,899   

Production taxes

     1,050        —           —          1,050   

Gathering and transportation

     3,669        1,184         —          4,853   

Depreciation, depletion and amortization

     55,679        21,377         —          77,056   

Asset retirement obligation accretion

     6,693        706         —          7,399   

General and administrative expenses

     18,104        —           —          18,104   

Derivative (gain)

     (17,323     —           —          (17,323
  

 

 

   

 

 

    

 

 

   

 

 

 

Total costs and expenses

     117,726        32,312         —          150,038   
  

 

 

   

 

 

    

 

 

   

 

 

 

Operating income

     57,209        38,124         —          95,333   

Earnings of affiliates

     24,780        —           (24,780     —     

Interest expense:

         

Incurred

     14,721        —           —          14,721   

Capitalized

     (3,163     —           —          (3,163

Loss on extinguishment of debt

     2,031        —           —          2,031   

Interest income

     6        —           —          6   
  

 

 

   

 

 

    

 

 

   

 

 

 

Income before income tax expense

     68,406        38,124         (24,780     81,750   

Income tax expense

     15,478        13,344         —          28,822   
  

 

 

   

 

 

    

 

 

   

 

 

 

Net income

   $ 52,928      $ 24,780       $ (24,780   $ 52,928   
  

 

 

   

 

 

    

 

 

   

 

 

 

Condensed Consolidating Statement of Income for the Nine Months Ended September 30, 2011

 

     Parent
Company
    Guarantor
Subsidiaries
     Eliminations     Consolidated
W&T
Offshore, Inc.
 
     (In thousands)  

Revenues

   $ 507,689      $ 201,459       $ —        $ 709,148   
  

 

 

   

 

 

    

 

 

   

 

 

 

Operating costs and expenses:

         

Lease operating expenses

     130,001        29,900         —          159,901   

Production taxes

     2,183        —           —          2,183   

Gathering and transportation

     9,990        3,213         —          13,203   

Depreciation, depletion and amortization

     155,874        62,800         —          218,674   

Asset retirement obligation accretion

     21,125        2,118         —          23,243   

General and administrative expenses

     51,653        2,582         —          54,235   

Derivative (gain)

     (10,815     —           —          (10,815
  

 

 

   

 

 

    

 

 

   

 

 

 

Total costs and expenses

     360,011        100,613         —          460,624   
  

 

 

   

 

 

    

 

 

   

 

 

 

Operating income

     147,678        100,846         —          248,524   

Earnings of affiliates

     65,550        —           (65,550     —     

Interest expense:

         

Incurred

     36,913        —           —          36,913   

Capitalized

     (6,654     —           —          (6,654

Loss on extinguishment of debt

     22,694        —           —          22,694   

Interest income

     22        —           —          22   
  

 

 

   

 

 

    

 

 

   

 

 

 

Income before income tax expense

     160,297        100,846         (65,550     195,593   

Income tax expense

     33,545        35,296         —          68,841   
  

 

 

   

 

 

    

 

 

   

 

 

 

Net income

   $ 126,752      $ 65,550       $ (65,550   $ 126,752   
  

 

 

   

 

 

    

 

 

   

 

 

 

 

18


Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Condensed Consolidating Statement of Income for the Three Months Ended September 30, 2010

 

     Parent
Company
    Guarantor
Subsidiaries
     Eliminations     Consolidated
W&T
Offshore, Inc.
 
         
         
     (In thousands)  

Revenues

   $ 140,410      $ 29,165       $ —        $ 169,575   
  

 

 

   

 

 

    

 

 

   

 

 

 

Operating costs and expenses:

         

Lease operating expenses

     31,091        3,280         —          34,371   

Production taxes

     276        —           —          276   

Gathering and transportation

     4,225        382         —          4,607   

Depreciation, depletion and amortization

     59,756        9,295         —          69,051   

Asset retirement obligation accretion

     6,119        145         —          6,264   

General and administrative expenses

     13,389        —           —          13,389   

Derivative loss

     4,770        —           —          4,770   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total costs and expenses

     119,626        13,102         —          132,728   
  

 

 

   

 

 

    

 

 

   

 

 

 

Operating income

     20,784        16,063         —          36,847   

Earnings of affiliates

     10,441        —           (10,441     —     

Interest expense:

         

Incurred

     10,485        —           —          10,485   

Capitalized

     (1,345     —           —          (1,345

Interest income

     150        —           —          150   
  

 

 

   

 

 

    

 

 

   

 

 

 

Income before income tax expense

     22,235        16,063         (10,441     27,857   

Income tax expense (benefit)

     (4,953     5,622         —          669   
  

 

 

   

 

 

    

 

 

   

 

 

 

Net income

   $ 27,188      $ 10,441       $ (10,441   $ 27,188   
  

 

 

   

 

 

    

 

 

   

 

 

 

Condensed Consolidating Statement of Income for the Nine Months Ended September 30, 2010

 

     Parent
Company
    Guarantor
Subsidiaries  (1)
     Eliminations     Consolidated
W&T
Offshore, Inc.
 
         
         
     (In thousands)  

Revenues

   $ 470,506      $ 48,321       $ —        $ 518,827   
  

 

 

   

 

 

    

 

 

   

 

 

 

Operating costs and expenses:

         

Lease operating expenses

     113,004        9,190         —          122,194   

Production taxes

     788        —           —          788   

Gathering and transportation

     12,324        596         —          12,920   

Depreciation, depletion and amortization

     186,511        15,359         —          201,870   

Asset retirement obligation accretion

     18,435        241         —          18,676   

General and administrative expenses

     36,870        1,273         —          38,143   

Derivative (gain)

     (8,500     —           —          (8,500
  

 

 

   

 

 

    

 

 

   

 

 

 

Total costs and expenses

     359,432        26,659         —          386,091   
  

 

 

   

 

 

    

 

 

   

 

 

 

Operating income

     111,074        21,662         —          132,736   

Earnings of affiliates

     14,080        —           (14,080     —     

Interest expense:

         

Incurred

     32,319        —           —          32,319   

Capitalized

     (4,090     —           —          (4,090

Interest income

     632        —           —          632   
  

 

 

   

 

 

    

 

 

   

 

 

 

Income before income tax expense

     97,557        21,662         (14,080     105,139   

Income tax expense

     184        7,582         —          7,766   
  

 

 

   

 

 

    

 

 

   

 

 

 

Net income

   $ 97,373      $ 14,080       $ (14,080   $ 97,373   
  

 

 

   

 

 

    

 

 

   

 

 

 

 

(1) Began operations on May 1, 2010. Includes only May 2010 to September 2010 activity.

 

19


Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2011

 

     Parent
Company
    Guarantor
Subsidiaries
    Eliminations     Consolidated
W&T
Offshore, Inc.
 
        
        
     (In thousands)  

Operating activities:

        

Net income

   $ 126,752      $ 65,550      $ (65,550   $ 126,752   

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

        

Depreciation, depletion, amortization and accretion

     176,999        64,918        —          241,917   

Amortization of debt issuance costs

     1,401        —          —          1,401   

Loss on extinguishment of debt

     22,694        —          —          22,694   

Share-based compensation

     6,437        —          —          6,437   

Derivative (gain)

     (10,815     —          —          (10,815

Cash payments on derivative settlements

     (9,239     —          —          (9,239

Deferred income taxes

     68,350        (8,908     —          59,442   

Earnings of affiliates

     (65,550     —          65,550        —     

Changes in operating assets and liabilities:

        

Oil and natural gas receivables

     (10,946     8,033        —          (2,913

Joint interest and other receivables

     7,465        —          —          7,465   

Insurance receivables

     18,971        —          —          18,971   

Income taxes

     (60,099     44,205        —          (15,894

Prepaid expenses and other assets

     (22,796     (165,495     165,690        (22,601

Asset retirement obligations

     (51,349     —          —          (51,349

Accounts payable and accrued liabilities

     25,717        (1,631     (194     23,892   

Other liabilities

     165,387        —          (165,496     (109
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     389,379        6,672        —          396,051   
  

 

 

   

 

 

   

 

 

   

 

 

 

Investing activities:

        

Acquisition of property interest in oil and natural gas properties

     (434,582     —          —          (434,582

Investment in oil and natural gas properties and equipment

     (183,735     (1,487     —          (185,222

Investment in subsidiary

     5,185        —          (5,185     —     

Proceeds from sales of oil and natural gas properties and equipment

     15        —          —          15   

Purchases of furniture, fixtures and other

     (318     —          —          (318
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (613,435     (1,487     (5,185     (620,107
  

 

 

   

 

 

   

 

 

   

 

 

 

Financing activities:

        

Issuance of 8.5% Senior Notes

     600,000        —          —          600,000   

Repurchase of 8.25% Senior Notes

     (450,000     —          —          (450,000

Borrowings of long-term debt – revolving bank credit facility

     512,000        —          —          512,000   

Repayments of long-term debt – revolving bank credit facility

     (418,000     —          —          (418,000

Repurchase premium and debt issuance costs

     (31,997     —          —          (31,997

Investment from parent

     —          (5,185     5,185        —     

Dividends to shareholders

     (8,936     —          —          (8,936
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     203,067        (5,185     5,185        203,067   
  

 

 

   

 

 

   

 

 

   

 

 

 

(Decrease) in cash and cash equivalents

     (20,989     —          —          (20,989

Cash and cash equivalents, beginning of period

     28,655        —          —          28,655   
  

 

 

   

 

 

   

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 7,666      $ —        $ —        $ 7,666   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

20


Table of Contents

W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Condensed Consolidating Statement of Cash Flows for the Nine Months Ended September 30, 2010

 

     Parent
Company
    Guarantor
Subsidiaries  (1)
    Eliminations     Consolidated
W&T
Offshore, Inc.
 
        
        
     (In thousands)  

Operating activities:

        

Net income

   $ 97,373      $ 14,080      $ (14,080   $ 97,373   

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

        

Depreciation, depletion, amortization and accretion

     204,946        15,600        —          220,546   

Amortization of debt issuance costs

     1,004        —          —          1,004   

Share-based compensation

     3,576        —          —          3,576   

Derivative (gain)

     (8,500     —          —          (8,500

Cash payments on derivative settlements

     (410     —          —          (410

Deferred income taxes

     4,253        2,230        —          6,483   

Earnings of affiliates

     (14,080     —          14,080        —     

Changes in operating assets and liabilities:

        

Oil and natural gas receivables

     12,941        (9,311     —          3,630   

Joint interest and other receivables

     29,542        —          —          29,542   

Insurance receivables

     36,763        —          —          36,763   

Income taxes

     78,801        5,351        —          84,152   

Prepaid expenses and other assets

     (1,464     (29,448     29,448        (1,464

Asset retirement obligations

     (62,620     —          —          (62,620

Accounts payable and accrued liabilities

     (32,632     2,484        —          (30,148

Other liabilities

     42,398        —          (29,448     12,950   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     391,891        986        —          392,877   
  

 

 

   

 

 

   

 

 

   

 

 

 

Investing activities:

        

Acquisition property interests in oil and natural gas properties

     —          (116,589     —          (116,589

Investment in oil and natural gas properties and equipment

     (126,441     (986     —          (127,427

Proceeds from sales of oil and natural gas properties and equipment

     1,335        —          —          1,335   

Investment in subsidiary

     (116,589     —          116,589        —     

Purchases of furniture, fixtures and other

     (405     —          —          (405
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (242,100     (117,575     116,589        (243,086
  

 

 

   

 

 

   

 

 

   

 

 

 

Financing activities:

        

Borrowings of long-term debt – revolving bank credit facility

     427,500        —          —          427,500   

Repayments of long-term debt – revolving bank credit facility

     (427,500     —          —          (427,500

Dividends to shareholders

     (7,467     —          —          (7,467

Investment from parent

     —          116,589        (116,589     —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     (7,467     116,589        (116,589     (7,467
  

 

 

   

 

 

   

 

 

   

 

 

 

Increase in cash and cash equivalents

     142,324        —          —          142,324   

Cash and cash equivalents, beginning of period

     38,187        —          —          38,187   
  

 

 

   

 

 

   

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 180,511      $ —        $ —        $ 180,511   
  

 

 

   

 

 

   

 

 

   

 

 

 
(1) Began operations on May 1, 2010. Includes only May 2010 to September 2010 activity.

 

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

Forward-Looking Statements

The following discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q. The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act, that involve risks, uncertainties and assumptions. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Certain factors that may affect our financial condition and results of operations are discussed in Item 1A “Risk Factors” and Item 7A “Quantitative and Qualitative Disclosures About Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2010 and may be discussed or updated from time to time in subsequent reports filed with the SEC. We assume no obligation, nor do we intend, to update these forward-looking statements. Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “W&T,” “we,” “us,” “our” and the “Company” refer to W&T Offshore, Inc. and its consolidated subsidiaries.

Overview

We are an independent oil and natural gas producer focused primarily in the Gulf of Mexico and onshore Texas. We have grown through acquisitions, exploitation and exploration and currently hold working interests in approximately 67 producing properties or fields capable of production in federal and state waters. The majority of our daily production is currently derived from offshore wells we operate. In May 2011, we closed on the acquisition of the Permian Basin Properties as described below. After completing this acquisition and acquiring other leasehold interests, we now hold working interests in over 173,000 net acres onshore in Texas. Acquiring these onshore properties has diversified our business by having both significant offshore and onshore operations.

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil and natural gas production and the price that we receive for such production. Our production volumes for the first nine months of 2011 was comprised of approximately 47% oil, condensate and natural gas liquids and 53% natural gas, determined using the ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or natural gas liquids. The conversion ratio does not assume price equivalency, and the price per one thousand cubic feet equivalent (“Mcfe”) for oil and natural gas liquids may differ significantly from the price per Mcf for natural gas. For example, for the first nine months of 2011, our average realized price for oil and NGLs on a Mcfe basis was $15.51 compared to $4.34 per Mcf for natural gas. For the first nine months of 2011, our combined total production of oil, condensate, natural gas liquids and natural gas was approximately 14.9% higher on a Mcfe basis than during the same period in 2010.

During August 2011, we completed the acquisition of Shell’s 64.3% interest in the Fairway Field along with a like interest in the associated Yellowhammer gas processing plant, with an effective date of September 1, 2010. Estimates of proved reserves as of June 30, 2011 were 54.5 billion cubic feet equivalent (“Bcfe”). The adjusted purchase price was comprised of $40.0 million of cash, which was funded through borrowings under our revolving bank credit facility, and we assumed the ARO associated with the properties and plant which we have currently estimated to be $7.8 million. We are finalizing our assessment of the fair values of the assets acquired and liabilities assumed. Therefore, the purchase price allocation is preliminary and is subject to change.

During May 2011, we completed the acquisition of approximately 21,900 gross acres (21,500 net acres) of oil and gas leasehold interests in the Permian Basin Properties from Opal. Including adjustments from an effective date of January 1, 2011, the adjusted purchase price was $397.1 million. Although further adjustments could occur to the purchase price, no further adjustments are expected at this time. We acquired estimated proved reserves of approximately 30 million barrels of oil equivalent (182 Bcfe) (using a 6 to 1 Mcf to barrel equivalency) as of December 31, 2010, comprised of approximately 91% oil and natural gas liquids and which are approximately 78% proved undeveloped. Capital expenditures associated with planned development activities for these properties from the closing date of May 11, 2011 to December 31, 2011 are currently estimated to be between $70 million and $80 million. The acquisition was funded from cash on hand and borrowings under our revolving bank credit facility.

 

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During 2010, we closed on two major acquisitions. In April 2010, we acquired two deepwater properties from Total and in November 2010, we acquired three deepwater fields from Shell. These transactions are described in Financial Statements - Note 2 – Acquisitions under Part I, Item 1 of this Form 10-Q.

The third-party pipeline used by our Main Pass 108, 98 and 180 fields, which had been offline since June 2010, became operational on March 31, 2011. In the second quarter of 2011, we continued to increase production in this area. In September 2011, these fields produced approximately 44 MMcfe per day, made up of 33,083 Mcf of natural gas and 1,834 barrels of oil/NGLs per day.

Prices for oil have continued to be volatile in 2011. For the nine months ended September 30, 2011, our average realized sales price for oil and NGLs (unhedged) increased significantly over the comparable period in 2010. The majority of our oil production is priced using the posted spot price for West Texas Intermediate (“WTI”) as a base price plus a premium depending on the type of crude oil. WTI is frequently used to value domestically produced crude oil. Our offshore oil production, which is comprised of various crudes including Light Louisiana Sweet, Heavy Louisiana Sweet and Poseidon, started selling at a significant premium relative to WTI earlier this year. In 2011 compared to 2010, our realized oil sales price increased 33.5%, compared to a 22.8% increase in the posted spot price for WTI. Our crudes have better reflected the international oil market prices, as measured using Brent crude, which increased 44.6% for this time frame. Oil prices continue to be impacted by market fundamentals such as supply and demand and also by political events and disruptions throughout the world, including events in Greece, Japan, Africa and the Middle East. Long-term forecasts for oil demand, and therefore global oil prices, continue to be favorable in several key growing markets, specifically China and India.

The premiums received on our offshore oil production have been up to $24.00 per barrel for the nine months ended September 30, 2011. In comparison, the average premium spread between Light Louisiana Sweet crude and WTI crude was approximately $3.00 per barrel during 2010. We may continue to experience higher premiums to WTI crude in our future sales of offshore crude oil until such time as the causative factors are resolved. We cannot predict with any certainty how long such pricing conditions will last.

Natural gas prices are much more affected by domestic issues, such as supply, local demand issues and domestic economic conditions. The Henry Hub posted spot price for natural gas was $4.22 per MMBtu for the nine months ended September 30, 2011 representing a decrease of 7.5% from $4.56 per MMBtu for the same period in 2010. The price for natural gas in the nine months ended September 30, 2011 ranged from a low of $3.68 per MMBtu to a high of $4.92 per MMBtu and the range in the same period of 2010 was from $3.72 to $7.51 per MMBtu. During the nine months ended September 30, 2011, the average realized sales price of our natural gas (unhedged) decreased 8.6% from the comparable period of 2010. We are expecting continued weakness in natural gas prices unless demand for natural gas increases as a result of a strong economic recovery, drilling activity subsides dramatically or forced production shut-ins occur. There is also a risk that, as a result of successful exploration and development activities in the shale areas coupled with the availability of increasing amounts of liquefied natural gas, increased supplies of natural gas will offset or mitigate the impact of any natural gas shut-ins or demand increases resulting from improved economic conditions. According to industry sources, the rig count for horizontal drilling rigs, used primarily in the shale formation areas such as Louisiana, Arkansas, Texas, North Dakota and Pennsylvania, has reached or exceeded record levels. Further, such sources indicate that onshore natural gas producers have continued to drill in attempts to yield production sufficient to preserve existing leases. Seasonal weather conditions also impact the demand for and price of natural gas.

Revenue from our offshore production is highly dependent on pipelines owned by others to access markets for our products. To the extent that the price such pipelines charge us increases, our revenues from the sales of our products would go down or transportation costs would increase, the result of either would be a reduction in operating income. Certain pipelines have filed tariffs to increase the amounts they charge us and we believe that we have limited alternatives to use other pipelines.

Should prices decline for oil and natural gas in the future, it would negatively impact our future oil and natural gas revenues, earnings and liquidity, and could result in ceiling test write-downs of the carrying value of our oil and natural gas properties, create issues with financial ratio compliance, and result in a reduction of the borrowing base associated with our credit agreement, depending on the severity of such declines. If those were to occur and were significant, it may limit the willingness of financial institutions and investors to provide capital to us and others in the oil and natural gas industry.

In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in the deep water of the Gulf of Mexico. As a result of the explosion and ensuing fire, the rig sank, causing loss of life, and created a major oil spill that produced economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE”) issued a

 

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series of “Notices to Lessees” (“NTLs”), and other significant changes in regulations. In addition, the BOEMRE implemented a six-month moratorium on drilling activities which began in May 2010. There also continue to be many proposed changes in laws, regulations, guidance and policy in response to the Deepwater Horizon explosion and spill. After the moratorium ended in 2010, it was not until March 2011 that deep water drilling permits began to be issued, and even then only sporadically, to continue drilling activities that had commenced prior to the Deepwater Horizon incident. Since March 2011, deepwater drilling permits have been issued, albeit at the slower and more measured pace than before the Deepwater Horizon event. The most significant regulatory changes since the Deepwater Horizon event are regulations related to assessing the potential environmental impact of future spills using worse case discharge scenarios on a well-by-well basis, spill response documentation, compliance reviews, operator practices related to safety and implementing a safety and environmental management system. The new regulations and increased review process increases the time it takes to obtain drilling permits and increases the cost of operations. As these new regulations and guidance continue to evolve, we cannot estimate the cost and impact to our business at this time. The permitting process is also slow and inconsistent for shallow water work and even for plug and abandonment activities. This could lead to increased costs and performing work at less than optimal effectiveness. We have not experienced delays in obtaining permits related to our onshore operations.

In October 2011, the BOEMRE was split into three separate entities: the Office of National Resources Revenue (“ONRR”), which assumed the functions of the Minerals Revenue Management Program; the Bureau of Ocean Energy Management (“BOEM”), which is responsible for managing development of the nation’s offshore resources in an environmentally and economically responsible way; and the Bureau of Safety and Environmental Enforcement (“BSEE”), which is responsible for enforcement of safety and environmental regulations.

 

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Results of Operations

The following table sets forth selected financial data for the periods indicated (all values are net to our interest unless indicated otherwise):

 

     Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
     2011     2010     Change     %     2011     2010     Change     %  
     (In thousands, except percentages and per share data)  

Financial:

                

Revenues:

                

Oil and NGLs

   $ 183,969      $ 126,325      $ 57,644        45.6   $ 537,400      $ 366,567      $ 170,833        46.6

Natural gas

     61,174        47,236        13,938        29.5     170,753        156,025        14,728        9.4

Other

     228        (3,986     4,214        NM        995        (3,765     4,760        NM   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     245,371        169,575        75,796        44.7     709,148        518,827        190,321        36.7

Operating costs and expenses:

                

Lease operating expenses

     58,899        34,371        24,528        71.4     159,901        122,194        37,707        30.9

Production taxes

     1,050        276        774        280.4     2,183        788        1,395        177.0

Gathering and transportation

     4,853        4,607        246        5.3     13,203        12,920        283        2.2

Depreciation, depletion, amortization and accretion

     84,455        75,315        9,140        12.1     241,917        220,546        21,371        9.7

General and administrative expenses

     18,104        13,389        4,715        35.2     54,235        38,143        16,092        42.2

Derivative (gain) loss

     (17,323     4,770        (22,093     NM        (10,815     (8,500     (2,315     27.2
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     150,038        132,728        17,310        13.0     460,624        386,091        74,533        19.3
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     95,333        36,847        58,486        158.7     248,524        132,736        115,788        87.2

Interest expense, net of amounts capitalized

     11,558        9,140        2,418        26.5     30,259        28,229        2,030        7.2

Loss on extinguishment of debt (1)

     2,031        —          2,031        NM        22,694        —          22,694        NM   

Interest income

     6        150        (144     (96.0 %)      22        632        (610     (96.5 %) 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income before income tax expense

     81,750        27,857        53,893        193.5     195,593        105,139        90,454        86.0

Income tax expense

     28,822        669        28,153        NM        68,841        7,766        61,075        786.4
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 52,928      $ 27,188      $ 25,740        94.7   $ 126,752      $ 97,373      $ 29,379        30.2
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Basic and diluted earnings per common share

   $ 0.70      $ 0.36      $ 0.34        94.4   $ 1.68      $ 1.30      $ 0.38        29.2

 

(1) In June 2011 and July 2011, we repurchased the entire $450 million outstanding of our 8.25% Senior Notes, which resulted in a loss on extinguishment of debt of $2.0 million and $22.0 million for the three and nine months ended September 30, 2011, respectively. In May 2011, we entered into the Fourth Amended and Restated Credit Agreement, which replaced the Prior Credit Agreement. Unamortized debt issuance costs of $0.7 million related to the Prior Credit Agreement were expensed for the nine months ended September 30, 2011. For additional information about our revolving bank credit facility and long-term debt, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.

NM = percentage change not meaningful

 

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The following table sets forth selected financial and operating data for the periods indicated (all values are net to our interest unless indicated otherwise):

 

    Three Months Ended
September 30,
    Nine Months Ended
September 30,
 
    2011     2010     Change     %     2011     2010     Change     %  

Operating:

               

Net sales:

               

Natural gas (Bcf)

    14.3        10.6        3.7        34.9     39.4        32.9        6.5        19.8

Oil and NGLs (MMBbls)

    2.0        1.8        0.2        11.1     5.8        5.3        0.5        9.4

Total natural gas and oil (Bcfe) (1)

    26.5        21.6        4.9        22.7     74.0        64.4        9.6        14.9

Total natural gas and oil (MMBoe) (1)

    4.4        3.6        0.8        22.2     12.3        10.7        1.6        15.0

Average daily equivalent sales (MMcfe/d)

    287.9        235.3        52.6        22.4     271.2        235.9        35.3        15.0

Average realized sales prices (Unhedged):

               

Natural gas ($/Mcf)

  $ 4.27      $ 4.47      $ (0.20     (4.5 %)    $ 4.34      $ 4.75      $ (0.41     (8.6 %) 

Oil and NGLs($/Bbl)

    90.84        68.35        22.49        32.9     93.08        69.73        23.35        33.5

Natural gas equivalent ($/Mcfe)

    9.26        8.02        1.24        15.5     9.57        8.12        1.45        17.9

Average realized sales prices (Hedged):

               

Natural gas ($/Mcf)

  $ 4.27      $ 4.58      $ (0.31     (6.8 %)    $ 4.34      $ 4.91      $ (0.57     (11.6 %) 

Oil and NGLs ($/Bbl)

    90.39        68.35        22.04        32.2     91.48        69.55        21.93        31.5

Natural gas equivalent ($/Mcfe)

    9.22        8.07        1.15        14.3     9.44        8.18        1.26        15.4

Average per Mcfe ($/Mcfe):

               

Lease operating expenses

  $ 2.22      $ 1.59      $ 0.63        39.6   $ 2.16      $ 1.90      $ 0.26        13.7

Gathering and transportation

    0.18        0.21        (0.03     (14.3 %)      0.18        0.20        (0.02     (10.0 %) 
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Production costs

    2.40        1.80        0.60        33.3     2.34        2.10        0.24        11.4

Production taxes

    0.04        0.01        0.03        300.0     0.03        0.01        0.02        200.0

Depreciation, depletion, amortization and accretion

    3.19        3.48        (0.29     (8.3 %)      3.27        3.42        (0.15     (4.4 %) 

General and administrative expenses

    0.68        0.62        0.06        9.7     0.73        0.59        0.14        23.7
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
  $ 6.31      $ 5.91      $ 0.40        6.8   $ 6.37      $ 6.12      $ 0.25        4.1
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total number of offshore wells drilled (gross)

    1        —          1        NM        4        5        (1     (20.0 %) 

Total number of onshore wells drilled (gross)

    21        2        19        NM        31        2        29        NM   

Total number of offshore productive wells drilled (gross)

    1        —          1        NM        4        4        —          (0.0 %) 

Total number of onshore productive wells drilled (gross)

    20        —          20        NM        30        —          30        NM   

 

(1) The conversion to cubic feet equivalent and barrels of equivalent measures determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids (totals may not compute due to rounding). The conversion ratio does not assume price equivalency, and the price per Mcfe for oil and natural gas liquids may differ significantly from the price per Mcf for natural gas.

NM = percentage change not meaningful

 

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Three Months Ended September 30, 2011 Compared to the Three Months Ended September 30, 2010

Revenues. Total revenues increased $75.8 million, or 44.7%, to $245.4 million for the three months ended September 30, 2011, as compared to the same period in 2010. Oil and NGL revenues increased $57.6 million, natural gas revenues increased $13.9 million and other revenues increased $4.3 million. The oil and NGL revenue increase was attributable to a 32.9% increase in the average realized sales price to $90.84 per barrel for the three months ended September 30, 2011 from $68.35 per barrel for the same period in 2010, combined with an increase of 11.1% in sales volumes. The sales volume increase for oil and NGL is primarily attributable to increases associated with properties acquired in 2011 and 2010. The increase in natural gas revenue resulted from a 34.9% increase in sales volumes, partially offset by a 4.5% decrease in the average realized natural gas sales price. For the three months ended September 30, 2011, the natural gas average realized sales price was $4.27 per Mcf compared to $4.47 per Mcf for the same period in 2010. The sales volume increase for natural gas is primarily attributable to increases associated with our acquisition activities, the Main Pass 108 fields resuming production and successful exploration efforts. Other revenue changed primarily due to a disallowance of $4.7 million by the BOEMRE of royalty relief for transportation of deepwater production through our subsea pipeline system that was recorded in the three months ended September 30, 2010.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, and hurricane remediation costs net of insurance claims, increased $24.5 million to $58.9 million for the three months ended September 30, 2011 compared to the same period in 2010. On a per Mcfe basis, lease operating expenses increased to $2.22 per Mcfe during the three months ended September 30, 2011 compared to $1.59 per Mcfe during the same period in 2010. On a component basis, base lease operating expenses, hurricane remediation costs net of insurance claims, workover costs, insurance premiums and facility expenses increased $10.1 million, $6.6 million, $4.3 million, $2.1 million and $1.4 million, respectively. The increase in base lease operating expenses is primarily attributable to expenses associated with the properties acquired in 2011 and 2010, higher costs at our various non-operated properties, increased processing fees associated with our Daniel Boone field production and expenses billed to a third party in 2010 related to a divestiture that did not occur in 2011. Hurricane remediation costs net of insurance claims increased due to higher reimbursements received in the 2010 period. Workover costs increased primarily due to work performed at our new Permian Basin Properties. The increase in insurance premiums resulted primarily from higher premiums on our insurance policies covering well control and hurricane damage which incorporates additional acquired properties. The increase in facility expenses is primarily attributable to work performed at the Fairway Properties.

Production taxes. Production taxes increased to $1.1 million for the three months ended September 30, 2011 compared to $0.3 million in the prior year primarily due to the Permian Basin Properties operations and are currently not a large component of our operating costs. Most of our production is from federal waters where there are no production taxes while onshore operations are subject to production taxes.

Gathering and transportation costs. Gathering and transportation costs were basically flat for the quarter compared to the prior year.

Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, decreased to $3.19 per Mcfe for the three months ended September 30, 2011 from $3.48 per Mcfe in the prior year. On a nominal basis, DD&A increased to $84.5 million for the three months ended September, 2011 from $75.3 million in the prior year. The decrease to DD&A on a per Mcfe basis was primarily due to increases in proved reserves while DD&A on a nominal basis increased due to higher production volumes.

General and administrative expenses (“G&A”). G&A expenses increased to $18.1 million for the three months ended September 30, 2011 from $13.4 million for the prior year primarily due to higher incentive compensation as a result of improved financial and operational performance, and expanded activities onshore and offshore. In addition, costs associated with acquisition activities, transition service fees paid to the sellers of the acquired properties, litigation settlements and accruals and increased professional fees resulted in higher G&A. On a per Mcfe basis, G&A was $0.68 per Mcfe for the three months ended September 30, 2011, compared to $0.62 per Mcfe for the same period in 2010.

Derivative (gain)/loss. For the three months ended September 30, 2011, our derivative gain of $17.3 million related to a change in the fair value of our commodity derivatives as a result of changes in crude oil prices. For the comparable period of 2010, our derivative loss of $4.8 million related to a loss from our commodity derivatives as a result of changes in crude oil and natural gas prices. For additional details about our derivatives, refer to Financial Statements – Note 5 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q.

 

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Interest expense. Interest expense incurred increased to $14.7 million for the three months ended September 30, 2011 from $10.5 million for the same period in 2010. During 2011, the amounts outstanding for our senior notes increased to $600 million from $450 million and the senior note annual interest rate increased to 8.5% from 8.25%. In addition, average borrowings on our revolving bank credit facility increased. During the three months ended September 30 of 2011 and 2010, $3.2 million and $1.3 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties which increased with the Permian Basin Properties acquisition. For additional information about our long-term debt and revolving bank credit facility, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.

Loss on extinguishment of debt. The loss on extinguishment of debt of $2.0 million was attributable to the redemption of the remaining outstanding balance of $43.9 million of the 8.25% Senior Notes. The amount expensed included the call premium paid to the remaining note holders pursuant to the terms of the note and to write off the balance of unamortized debt issuance costs related to the 8.25% Senior Notes. For additional information about our long-term debt, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.

Income tax expense. Income tax expense increased to $28.8 million for the three months ended September 30, 2011 compared to $0.7 million for the same period of 2010. Our effective tax rate for the three months ended September 30, 2011 was 35.3%, which approximates the federal and state statutory rates. Our effective tax rate for the three months ended September 30, 2010 was 2.4% and primarily reflects a reduction in our valuation allowance that was recorded in prior years.

Nine Months Ended September 30, 2011 Compared to the Nine Months Ended September 30, 2010

Revenues. Total revenues increased $190.3 million, or 36.7%, to $709.1 million for the nine months ended September 30, 2011, as compared to the same period in 2010. Oil and NGL revenues increased $170.8 million, natural gas revenues increased $14.7 million and other revenues increased $4.8 million. The oil and NGL revenue increase was attributable to a 33.5% increase in the average realized sales price to $93.08 per barrel for the nine months ended September 30, 2011 from $69.73 per barrel for the same period in 2010, combined with an increase of 9.4% in sales volumes. The sales volume increase for oil and NGL is primarily attributable to increases associated with properties acquired in 2011 and 2010. The increase in natural gas revenue resulted from a 19.8% increase in sales volumes, partially offset by an 8.6% decrease in the average realized natural gas sales price to $4.34 per Mcf for the nine months ended September 30, 2011 from $4.75 per Mcf for the same period in 2010. The sales volume increase for natural gas is primarily attributable to increases associated with our acquisition activities, the Main Pass 108 fields resuming production and successful exploration efforts. Other revenue changed primarily due to a disallowance of $4.7 million by the BOEMRE of royalty relief for transportation of deepwater production through our subsea pipeline system that was recorded in the three months ended September 30, 2010.

Lease operating expenses. Lease operating expenses, which include base lease operating expenses, insurance, workovers, maintenance on our facilities, and hurricane remediation costs net of insurance claims, increased $37.7 million to $159.9 million in the nine months ended September 30, 2011 compared to the same period in 2010. On a per Mcfe basis, lease operating expenses increased to $2.16 per Mcfe during the nine months ended September 30, 2011 compared to $1.90 per Mcfe during the same period of 2010. On a component basis, base lease operating expenses, hurricane remediation costs net of insurance claims, facility expenses and workover costs increased $15.3 million, $11.5 million, $11.0 million, and $2.3 million, respectively. As a partial offset, insurance premiums decreased $2.5 million. The increase in base lease operating expenses is primarily attributable to expenses associated with the properties acquired in 2011 and 2010, higher costs at our various non-operated properties, increased processing fees associated with our Daniel Boone field production and expenses billed to a third party in 2010 related to a divestiture that did not occur in 2011. Hurricane remediation costs net of insurance claims increased primarily due to higher reimbursements received in the 2010 period. The increase in facility expenses is primarily attributable to work performed on the tendon tension monitoring system and mechanical repairs at our Matterhorn platform, the pipeline repairs at our Ship Shoal 300 field to remove paraffin and inspection fees at our Main Pass 252 platforms. Workover costs increased due to work performed at our new Permian Basin Properties and expenses at the Main Pass 108 field, partially offset by projects in 2010 that did not occur in 2011. The decrease in insurance premiums resulted primarily from lower premiums on our insurance policies covering well control and hurricane damage that cover the policy period June 1, 2010 to June 1, 2011. Our premiums increased effective with the June 1, 2011 renewal.

Production taxes. Production taxes increased to $2.2 million for the nine months ended September 30, 2011 compared to $0.8 million in the same period of 2010 primarily due to the Permian Basin Properties operations and are currently not a large component of our operating costs. Most of our production is from federal waters where there are no production taxes while onshore operations are subject to production taxes.

 

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Gathering and transportation costs. Gathering and transportation costs were basically flat for the nine months ended September 30, 2011 compared to the same period in 2010.

Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, decreased to $3.27 per Mcfe for the nine months ended September 30, 2011 from $3.42 per Mcfe for the same period in 2010. On a nominal basis, DD&A increased to $241.9 million for the nine months ended September 30, 2011 from $220.5 million in the same period in 2010. The decrease to DD&A on a per Mcfe basis was primarily due to increases in proved reserves while DD&A on a nominal basis increased due to higher production volumes.

General and administrative expenses. General and administrative expenses increased to $54.2 million for the nine months ended September 30, 2011 from $38.1 million for the same period in 2010, primarily due to higher incentive compensation as a result of improved financial and operational performance, and expanded activities onshore and offshore. In addition, costs associated with acquisition activities, surety premiums, transition service fees paid to the sellers of the acquired properties, and litigation settlements and accruals resulted in higher G&A. Also, there were administration fees earned in 2010 related to an asset disposition and no such fees were earned in 2011. On a per Mcfe basis, G&A was $0.73 per Mcfe for the nine months ended September 30, 2011, compared to $0.59 per Mcfe for the same period in 2010.

Derivative (gain)/loss. For the nine months ended September 30, 2011, our derivative gain of $10.8 million related entirely to a change in the fair value of our commodity derivatives as a result of the changes in crude oil prices. For the nine months ended September 30, 2010, our derivative gain of $8.5 million related to a gain from our commodity derivatives of $8.8 million and a loss of $0.3 million related to our interest rate swap. For additional details about our derivatives, refer to Item 1 Financial Statements – Note 5 – Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q.

Interest expense. Interest expense incurred increased to $36.9 million for the nine months ended September 30, 2011 from $32.3 million for the same period in 2010. During 2011, the amounts outstanding for our senior notes increased to $600 million from $450 million and the senior note annual interest rate increased to 8.5% from 8.25%. During the nine months ended September 30 of 2011 and 2010, $6.7 million and $4.1 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties which increased with the Permian Basin Properties acquisition. For additional information about our long-term debt and revolving bank credit facility, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.

Loss on extinguishment of debt. The loss on extinguishment of debt of $22.7 million was attributable primarily to the repurchase of the $450 million outstanding of our 8.25% Senior Notes. The repurchase of the 8.25% Senior Notes was funded with a portion of the proceeds from the issuance of the 8.5% Senior Notes. The call premiums, unamortized debt issuance costs and other related expenses totaled $22.0 million. In addition, the previous revolving bank credit facility was replaced resulting in the write off of unamortized debt issuance costs of $0.7 million. For additional information about our long-term debt and revolving bank credit facility, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.

Income tax expense. Income tax expense increased to $68.8 million for the nine months ended September 30, 2011 compared to $7.8 million for the same period of 2010. Our effective tax rate for the nine months ended September 30, 2011 was 35.2%, which approximates the federal and state statutory rates. Our effective tax rate for the nine months ended September 30, 2010 was 7.4% and primarily reflects a reduction in our valuation allowance that was recorded in prior years.

Liquidity and Capital Resources

Our primary liquidity needs are to fund capital expenditures and strategic property acquisitions to allow us to replace our oil and natural gas reserves, repay outstanding borrowings and make related interest payments. We have funded our capital expenditures, including acquisitions, with cash on hand, cash provided by operations, securities offerings and bank borrowings. These sources of liquidity have historically been sufficient to fund our ongoing cash requirements.

Cash flow and working capital. Net cash provided by operating activities for the nine months ended September 30, 2011 was $396.1 million, compared to $392.9 million for the same period in 2010. The 2010 period included income tax refunds of $99.8 million primarily related to the Worker, Homeowner and Business Assistance Act of 2009 that allowed us to carry back losses to previously closed years, while the 2011 period included tax payments of $25.3 million. Otherwise, cash flow from operating activities increased $128 million due to substantially improved operating results. Our combined average realized sales price was 17.9% higher than the comparable 2010 period and our combined total production of oil, NGLs and natural gas during the nine months ended September 30, 2011 was 14.9% higher than the comparable 2010 period.

 

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Net cash used in investing activities during the nine months ended September 30, 2011 and 2010 were $620.1 million and $243.1 million, respectively, which primarily represents our investments in oil and natural gas properties. Major acquisitions consisted of the cash portion of the Permian Basin Properties ($394.6 million) and the Fairway Properties ($40.0 million) purchased in 2011 and the Matterhorn/Virgo Properties ($116.6 million) purchased in 2010. In addition, investments in other oil and natural gas properties and equipment were $185.2 million in the nine months ended September 30, 2011 compared to $127.4 million in the nine months ended September 30, 2010 with the increase primarily related to the Permian Basin Properties. There were minimal proceeds from sales of assets in the nine months ended September 30, 2011 and proceeds from asset sales were $1.3 million for the same period in 2010.

Net cash provided by financing activities was $203.1 million during the nine months ended September 30, 2011. Funds were provided through net borrowings on the revolving bank credit facility of $94 million and issuance of $600 million of 8.5% Senior Notes and partially offset by the repurchase of $450 million of the 8.25% Senior Notes, repurchase premium and debt issuance costs of $32.0 million and the payment of dividends of $8.9 million. See Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q for additional information on the senior notes transactions. Net cash used in financing activities during the nine months ended September 30, 2010 was $7.5 million which reflects dividend payments during the period.

At September 30, 2011, we had a cash balance of $7.7 million and $443.0 million of undrawn capacity available under the revolving bank credit facility which had a borrowing base of $537.5 million as of this date.

Credit agreement and long-term debt. At September 30, 2011, there was $94 million outstanding under our revolving bank credit facility compared to zero at December 31, 2010. At September 30, 2011, there was $600 million of our 8.5% Senior Notes outstanding and at December 31, 2010 there was $450 million outstanding of our 8.25% Senior Notes. We believe that cash provided by operations, borrowings available under our revolving bank credit facility and other external sources of liquidity should be sufficient to fund our ongoing cash requirements.

On May 5, 2011, we entered into the Credit Agreement which provides a revolving bank credit facility with an initial borrowing base of $525 million collateralized by our oil and natural gas properties. The Credit Agreement terminates on May 5, 2015 and replaced the Prior Credit Agreement, which would have expired July 23, 2012. Fees and transactions costs related to the Credit Agreement were approximately $5.9 million. The terms of the Credit Agreement are substantially similar to the terms of the Prior Credit Agreement. Availability under the Credit Agreement is subject to a semi-annual borrowing base redetermination set at the discretion of our lenders. The amount of the borrowing base is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. Any determination by our lenders to change our borrowing base will result in a similar change in the size of our revolving bank credit facility. The borrowing base was re-determined in October 2011 and was increased to $575 million.

The Credit Agreement contains various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio and a maximum leverage ratio, as defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement as of September 30, 2011. During the nine months ended September 30, 2011, borrowings outstanding on the revolving bank credit facility increased to $300 million primarily to fund the acquisition of the Permian Basin Properties, which also included funding from cash on hand. These borrowings were subsequently reduced to $94 million as of September 30, 2011, primarily by utilizing funds received from the senior note transactions described below and net cash from operations, partially offset by capital expenditures. Letters of credit outstanding as of September 30, 2011 were $0.5 million.

On June 10, 2011, we issued $600 million of 8.5% Senior Notes and used a portion of the net proceeds to repurchase the $450 million outstanding of our 8.25% Senior Notes. The net cash provided by these senior notes transactions, which includes initial purchaser fees, redemption premiums and other transactions costs, was $123.9 million. These transactions extended the maturity date of our long-term debt and we used the net proceeds to pay down a portion of amounts outstanding under the revolving bank credit facility. The 8.5% Senior Notes mature on June 15, 2019. Interest is payable semi-annually in arrears on June 15 and December 15 of each year beginning on December 15, 2011. For additional information about our credit agreement and long-term debt, refer to Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q.

Derivatives. From time to time, we use various derivative instruments to manage a portion of our exposure to commodity price risk from sales of oil and natural gas and interest rate risk from floating interest rates on our revolving bank credit facility. As of September 30, 2011, our outstanding derivative instruments consisted of commodity option contracts

 

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relating to approximately 0.4 MMBbls and 1.1 MMBbls of our anticipated oil production for the balance of 2011 and the full year of 2012, respectively. For additional details about our derivatives, refer to Financial Statements – Note 5– Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q.

Hurricane Remediation and Insurance Claims. During the third quarter of 2008, Hurricane Ike, and to a much lesser extent Hurricane Gustav, caused property damage and disruptions to our exploration and production activities. Our insurance coverage policy limits at the time of Hurricane Ike were $150 million for property damage due to named windstorms (excluding certain damage incurred at our marginal facilities) and $250 million for, among other things, removal of wreckage if mandated by any governmental authority. The policies in effect on the occurrence dates of Hurricanes Ike and Gustav had a retention requirement of $10 million per occurrence. In 2008, we satisfied our $10 million retention requirement for Hurricane Ike in connection with two platforms that were toppled and were deemed total losses. The damage we incurred as a result of Hurricane Gustav was below our retention amount.

We recognize insurance receivables with respect to capital, repair and plugging and abandonment costs as a result of hurricane damage when we deem those to be probable of collection, which arises when our insurance underwriters’ adjuster reviews and approves such costs for payment by the underwriters. Claims that have been processed in this manner have customarily been paid on a timely basis.

In the nine months ended September 30, 2011 and 2010, we received cash of $18.9 million and $46.9 million, respectively, from our insurance carrier related to Hurricane Ike claims. We have recorded $1.7 million receivables as of September 30, 2011 for claims submitted and approved for payment as of this date. As of September 30, 2011, we have recorded in ARO an estimate of $57.1 million for additional costs to be incurred related to Hurricane Ike and we estimate that this work will be completed by the end of 2013. We expect to receive reimbursement for a portion of these costs from our insurance carrier once the costs are incurred, claims are processed and payments are approved, but cannot estimate the amount of reimbursement to be received at this time. Should necessary expenditures exceed our insurance coverage for damages incurred as a result of Hurricane Ike, or claims are denied by our insurance carrier for other reasons, we expect that our available cash on hand, cash flow from operations and the availability under our revolving bank credit facility will be sufficient to meet these future cash needs.

For a discussion of our hurricane remediation costs related to lease operating expenses incurred during the nine months ended September 30, 2011 and 2010, refer to Financial Statements – Note 3 – Hurricane Remediation and Insurance Claims under Part I, Item 1 of this Form 10-Q. Lease operating expenses will be offset in future periods to the extent that these costs incurred are approved for payment under our insurance policies.

We currently carry three layers of insurance coverage for our operating activities in the Gulf of Mexico. The current policy limits for well control and hurricane damage (defined as named windstorm in our policies) are up to $100 million and $120 million, respectively, and the policies are effective until June 1, 2012. We carry an additional $100 million of well control coverage effective until June 1, 2012 on certain wells at our Mahogany, Matterhorn, Virgo, Tahoe and SE Tahoe fields. A retention amount of $5 million for well control events and $37.5 million per hurricane occurrence must be satisfied by us before we are indemnified for losses. Certain properties we have deemed as non-core are not covered for hurricane damage; however, properties representing approximately 96% of our present value of estimated future net revenues discounted at 10% (“PV-10”) at December 31, 2010 are covered under our insurance policies for hurricane damage. Pollution causing a negative environmental impact is characterized as a covered component of each of the well control and hurricane sections of the policy.

Our general and excess liability policy, which is effective until May 1, 2012, provides for $250 million of liability coverage for bodily injury and property damage, including liability claims resulting from seepage, pollution or contamination. With respect to the Oil Spill Financial Responsibility (“OSFR”) requirement under the Oil Pollution Act (“OPA”), we are required to evidence $150 million of financial responsibility to the BSEE. We qualify to self-insure for $35 million of this amount and the remaining $115 million is covered by insurance. We may only collect proceeds under this OSFR policy after our well control, hurricane damage and excess liability policies have been exhausted.

The premiums for the above policies were $30 million compared to $22 million for the policies that expired in May and June of 2011. Although we have not been informed otherwise, in the future, our insurers may not continue to offer this type and level of coverage to us, or our costs may increase substantially as a result of increased premiums and the increased risk of uninsured losses that may have been previously insured, all of which could have a material adverse effect on our financial condition and results of operations. We are also exposed to the possibility that in the future we will be unable to buy insurance at any price or that if we do have a claim, the insurance companies will not pay our claim. However, we are not

 

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aware of any financial issues related to any of our insurance underwriters that would affect their ability to pay claims. We do not carry business interruption insurance.

Capital expenditures. The level of our investment in oil and natural gas properties changes from time to time depending on numerous factors, including the prices of oil and natural gas, acquisition opportunities, and the results of our exploration and development activities. The following table presents our capital expenditures for acquisitions, exploration, development and other leasehold costs:

 

     Nine Months Ended September 30,  
             2011                      2010          
     (in thousands)  

Acquisition of Permian Basin Properties

   $ 394,594       $ —     

Acquisition of Fairway Properties

     39,988         —     

Acquisition of Matterhorn/Virgo Properties

     —           116,589   

Exploration (1)

     40,045         68,640   

Development (1)

     128,255         40,474   

Seismic, capitalized interest, other leasehold costs

     16,922         18,313   
  

 

 

    

 

 

 

Acquisitions and investments in oil and gas property/equipment

   $ 619,804       $ 244,016   
  

 

 

    

 

 

 

 

(1) Reported by geography in the subsequent table.

The following table presents our exploration and development capital expenditures by geography:

 

     Nine Months Ended September 30,  
             2011                      2010          
     (in thousands)  

Conventional shelf

   $ 99,317       $ 93,777   

Deepwater

     3,072         6,429   

Deep shelf

     1,816         3,405   

Onshore

     64,095         5,503   
  

 

 

    

 

 

 

Exploration and development capital expenditures

   $ 168,300       $ 109,114   
  

 

 

    

 

 

 

Our 2011 capital expenditures were financed by cash flow from operating activities, cash on hand and additional borrowings. Our 2010 capital expenditures were financed by cash flow from operating activities and cash on hand.

During the nine months ended September 20, 2011, we participated in the drilling of 31 onshore wells and 4 offshore wells, all except one of which were successful. Of the successful onshore wells, nine onshore wells were exploration wells and 21 onshore wells were development wells, with one being in South Texas, one in East Texas and the others in the Permian Basin of West Texas. One onshore well in South Texas was unsuccessful. All of the offshore wells were successful and were drilled on the conventional shelf. One offshore well was an exploration well and the other three were development wells.

During the nine months ended September 30, 2010, we participated in the drilling of five offshore wells, four of which were successful. Of these successful wells, all four were on the conventional shelf with three being exploration wells and one a development well. We also participated in the drilling of two onshore wells, both of which were unsuccessful.

Our onshore acreage has increased during the nine months ended September 30, 2011 from approximately 5,000 net acres to approximately 173,000 net acres with the increases primarily from acreage acquired in East Texas and from the Permian Basin Properties acquisition.

Our total capital expenditure budget for 2011 is $310 million, which excludes acquisitions. Although there has been considerable shuffling of wells and focus areas since the original budget was prepared, we believe that the $310 million continues to be a reasonable estimate of our capital expenditures, excluding acquisitions, for 2011. The budget includes amounts for drilling and evaluation of wells, well completions, facilities capital, recompletions, seismic and leasehold items. Our 2011 capital budget is subject to change as conditions warrant and our budget is sufficiently flexible such that most any change can be made without incurring any contractor breakage or commitment fees.

 

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Capital expenditures associated with development activities for the Permian Basin Properties acquired in May 2011 from the closing date of May 11, 2011 to December 31, 2011 are currently estimated between $70 million and $80 million and are included in the total annual capital expenditure budget described above. For additional information on this acquisition, please see Financial Statements - Note 2 – Acquisitions under Part I, Item 1 of this Form 10-Q.

We intend to continue to pursue acquisitions and joint venture opportunities in the future. We are constantly evaluating attractive new opportunities and expect to continue to complement our drilling and exploitation projects with acquisitions providing acceptable rates of return. We anticipate funding our 2011 capital budget and acquisitions with internally generated cash flow, cash on hand, borrowings under our revolving bank credit facility, issuance of our 8.5% Se