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 March 31, 2013

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   þ    Accelerated filer   ¨
Non-accelerated filer   ¨    Smaller reporting company   ¨

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

As of May 6, 2013, there were 75,249,630 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 March 31, 2013 and December 31, 2012

     1   

Condensed Consolidated Statements of Income for the Three Months Ended March 31, 2013 and 2012

     2   

Condensed Consolidated Statement of Changes in Shareholders’ Equity for the Three Months Ended March 31, 2013

     3   

Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012

     4   

Notes to Condensed Consolidated Financial Statements

     5   

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

     23   

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     33   

Item 4. Controls and Procedures

     33   

PART II – OTHER INFORMATION

     34   

Item 1. Legal Proceedings

     34   

Item 1A. Risk Factors

     35   

Item 6. Exhibits

     35   

SIGNATURE

     36   

EXHIBIT INDEX

     37   


Table of Contents

PART I – FINANCIAL INFORMATION

 

Item 1. Financial Statements

W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

 

      March 31,
2013
    December 31,
2012
 
     (In thousands, except share data)  
     (Unaudited)  
Assets     

Current assets:

    

Cash and cash equivalents

   $ 12,277      $ 12,245   

Receivables:

    

Oil and natural gas sales

     97,309        97,733   

Joint interest and other

     35,681        56,439   

Income taxes

     45,638        47,884   
  

 

 

   

 

 

 

Total receivables

     178,628        202,056   

Deferred income taxes

     1,432        267   

Prepaid expenses and other assets

     22,363        25,555   
  

 

 

   

 

 

 

Total current assets

     214,700        240,123   

Property and equipment – at cost:

    

Oil and natural gas properties and equipment (full cost method, of which $125,485 at March 31, 2013 and $123,503 at December 31, 2012 were excluded from amortization)

     6,836,590        6,694,510   

Furniture, fixtures and other

     21,949        21,786   
  

 

 

   

 

 

 

Total property and equipment

     6,858,539        6,716,296   

Less accumulated depreciation, depletion and amortization

     4,759,198        4,655,841   
  

 

 

   

 

 

 

Net property and equipment

     2,099,341        2,060,455   

Restricted deposits for asset retirement obligations

     29,161        28,466   

Other assets

     18,855        19,943   
  

 

 

   

 

 

 

Total assets

   $ 2,362,057      $ 2,348,987   
  

 

 

   

 

 

 
Liabilities and Shareholders’ Equity     

Current liabilities:

    

Accounts payable

   $ 112,223      $ 123,885   

Undistributed oil and natural gas proceeds

     41,255        37,073   

Asset retirement obligations

     69,964        92,630   

Accrued liabilities

     39,067        21,021   
  

 

 

   

 

 

 

Total current liabilities

     262,509        274,609   

Long-term debt

     1,060,079        1,087,611   

Asset retirement obligations, less current portion

     308,261        291,423   

Deferred income taxes

     158,922        145,249   

Other liabilities

     8,288        8,908   

Commitments and contingencies

     —          —     

Shareholders’ equity:

    

Preferred stock, $0.00001 par value; 20,000,000 shares authorized; 0 issued at March 31, 2013 and December 31, 2012

     —          —     

Common stock, $0.00001 par value; 118,330,000 shares authorized; 78,118,803 issued and 75,249,630 outstanding at March 31, 2013, and December 31, 2012

     1        1   

Additional paid-in capital

     398,465        396,186   

Retained earnings

     189,699        169,167   

Treasury stock, at cost

     (24,167     (24,167
  

 

 

   

 

 

 

Total shareholders’ equity

     563,998        541,187   
  

 

 

   

 

 

 

Total liabilities and shareholders’ equity

   $ 2,362,057      $ 2,348,987   
  

 

 

   

 

 

 

See Notes to Condensed Consolidated Financial Statements.

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

     Three Months Ended March 31,  
     2013     2012  
     (In thousands, except per share data)  
     (Unaudited)  

Revenues

   $ 259,222      $ 235,886   
  

 

 

   

 

 

 

Operating costs and expenses:

    

Lease operating expenses

     59,341        56,663   

Production taxes

     1,789        1,485   

Gathering and transportation

     4,444        4,221   

Depreciation, depletion, amortization and accretion

     108,872        88,491   

General and administrative expenses

     21,087        29,479   

Derivative loss

     3,368        39,634   
  

 

 

   

 

 

 

Total costs and expenses

     198,901        219,973   
  

 

 

   

 

 

 

Operating income

     60,321        15,913   

Interest expense:

    

Incurred

     21,234        13,905   

Capitalized

     (2,433     (3,191
  

 

 

   

 

 

 

Income before income tax expense

     41,520        5,199   

Income tax expense

     14,902        1,981   
  

 

 

   

 

 

 

Net income

   $ 26,618      $ 3,218   
  

 

 

   

 

 

 

Basic and diluted earnings per common share

   $ 0.35      $ 0.04   

Dividends declared per common share

   $ 0.08      $ 0.08   

See Notes to Condensed Consolidated Financial Statements.

 

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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, 2012

     75,250       $ 1       $ 396,186       $ 169,167        2,869       $ (24,167   $ 541,187   

Cash dividends

     —           —           —           (6,020     —           —          (6,020

Share-based compensation

     —           —           2,255         —          —           —          2,255   

Other

     —           —           24         (66     —           —          (42

Net income

     —           —           —           26,618        —           —          26,618   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Balances at March 31, 2013

     75,250       $ 1       $ 398,465       $ 189,699        2,869       $ (24,167   $ 563,998   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

See Notes to Condensed Consolidated Financial Statements.

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     Three Months Ended March 31,  
     2013     2012  
     (In thousands)  
     (Unaudited)  

Operating activities:

    

Net income

   $ 26,618      $ 3,218   

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

    

Depreciation, depletion, amortization and accretion

     108,872        88,491   

Amortization of debt issuance costs and premium

     447        586   

Share-based compensation

     2,255        2,659   

Derivative loss

     3,368        39,634   

Cash payments on derivative settlements

     (4,271     (5,800

Deferred income taxes

     12,507        2,550   

Changes in operating assets and liabilities:

    

Oil and natural gas receivables

     423        9,516   

Joint interest and other receivables

     25,875        (2,170

Insurance receivables

     —          715   

Income taxes

     2,372        (10,386

Prepaid expenses and other assets

     4,911        3,884   

Asset retirement obligation settlements

     (23,464     (5,384

Accounts payable, accrued liabilities and other

     9,921        644   
  

 

 

   

 

 

 

Net cash provided by operating activities

     169,834        128,157   
  

 

 

   

 

 

 

Investing activities:

    

Investment in oil and natural gas properties and equipment

     (136,626     (84,626

Purchases of furniture, fixtures and other

     (114     (500
  

 

 

   

 

 

 

Net cash used in investing activities

     (136,740     (85,126
  

 

 

   

 

 

 

Financing activities:

    

Borrowings of long-term debt – revolving bank credit facility

     112,000        84,000   

Repayments of long-term debt – revolving bank credit facility

     (139,000     (117,000

Dividends to shareholders

     (6,020     (5,948

Other

     (42     (87
  

 

 

   

 

 

 

Net cash used in financing activities

     (33,062     (39,035
  

 

 

   

 

 

 

Increase in cash and cash equivalents

     32        3,996   

Cash and cash equivalents, beginning of period

     12,245        4,512   
  

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 12,277      $ 8,508   
  

 

 

   

 

 

 

See Notes to Condensed Consolidated Financial Statements.

 

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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 exploration, development and acquisition of oil and natural gas properties.

Interim Financial Statements. The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U. S. 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 included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012.

Reclassifications. Certain reclassifications have been made to the prior periods’ financial statements to conform to the current presentation. Income taxes was combined with Accrued liabilities on the Balance Sheet and changes in Other liabilities was combined with the changes in Accounts payable and accrued liabilities on the Statement of Cash Flows.

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.

Recent Accounting Developments. In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities which applies to certain items in the statement of financial position (balance sheet), and was further clarified in January 2013 by ASU 2013-01, Balance Sheet (Topic 210):Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarified the scope of ASU 2011-11 to derivative instruments, repurchase agreements and securities lending transactions. The effective date for the amendments is for annual periods beginning after January 1, 2013, and interim periods within those annual periods. ASU 2011-11 requires disclosures of the gross and net amounts for items eligible for offset in the balance sheet. Although the Company’s derivative financial instruments are subject to master netting agreements, the Company records its derivative financial instruments on a gross basis by contract; therefore, the ASUs did not significantly affect the Company’s disclosures. Other items of the ASUs were not applicable to the Company.

In February 2013, the FASB issued ASU 2013-04, Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, which requires an entity that is joint and severally liable to measure the obligation as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of one or more co-obligors. Required disclosures include a description of the nature of the arrangement, how the liability arose, the relationship with co-obligors and the terms and conditions of the arrangement. The effective date for the amendment is for annual periods beginning after December 15, 2013, and interim periods within those annual periods. The amendment is to be applied retrospectively to all prior periods presented. The Company is currently assessing the impact of ASU 2013-04 to determine the effects on the balance sheet and disclosures, if any.

2. Acquisitions and Divestitures

2013 Acquisitions and Divestitures. There were no acquisitions or divestures completed during the three months ended March 31, 2013.

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

2012 Acquisitions. On October 5, 2012, we acquired from Newfield Exploration Company and its subsidiary, Newfield Exploration Gulf Coast LLC (together, “Newfield”) certain oil and gas leasehold interests in the Gulf of Mexico (the “Newfield Properties”). The Newfield Properties consist of leases covering 78 offshore blocks on approximately 416,000 gross acres (268,000 net acres) (excluding overriding royalty interests), comprised of 65 blocks in the deepwater, six of which are producing, 10 blocks on the conventional shelf, four of which are producing, and an overriding royalty interest in three deepwater blocks, two of which are producing. Including adjustments from an effective date of July 1, 2012, the adjusted purchase price was $205.6 million and we assumed the future asset retirement obligations (“ARO”) associated with the Newfield Properties. The purchase price may be subject to further adjustments. The acquisition was funded from borrowings under our revolving bank credit facility and cash on hand. Subsequently in the same month, the amounts borrowed under our revolving bank credit facility were paid down with funds provided from the issuance of long-term debt in October 2012. (See Note 6 for information on long-term debt.)

The following table presents the preliminary purchase price allocation, including estimated adjustments, for the acquisition of the Newfield Properties (in thousands):

 

Oil and natural gas properties and equipment

   $ 237,278   

Asset retirement obligations – current

     (7,250

Asset retirement obligations – non-current

     (24,414
  

 

 

 

Total cash paid

   $ 205,614   
  

 

 

 

The acquisition was recorded at fair value, which was determined by applying the market and income approaches using Level 3 inputs. The Level 3 inputs were: (i) analysis of comparable transactions obtained from various third-parties, (ii) estimates of ultimate recoveries of reserves and (iii) estimates of discounted cash flows based on estimated reserve quantities, reserve categories, timing of production, costs to produce and develop reserves, future prices, ARO and discount rates. The estimates and assumptions were determined by management and third-parties. The fair value is based on subjective estimates and assumptions, which are inherently imprecise, and the actual realized values could vary significantly from these estimates. No goodwill was recorded for the Newfield Properties acquisition.

Revenue, Net Income and Pro Forma Financial Information — Unaudited

The Newfield Properties were not included in our consolidated results until the closing date of October 5, 2012. For the three months ended March 31, 2013, the Newfield Properties accounted for $28.6 million of revenue, $6.6 million of direct operating expenses, $10.5 million of depreciation, depletion, amortization and accretion (“DD&A”) and $4.0 million of income taxes, resulting in $7.5 million of net income. The net income attributable to these properties does not reflect certain expenses, such as general and administrative expense (“G&A”) 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 Newfield Properties are not recorded in a separate entity for tax purposes; therefore, income tax was estimated using the federal statutory tax rate. There were no expenses associated with acquisition activities and transition activities related to the acquisition of the Newfield Properties for the three months ended March 31, 2012.

The unaudited pro forma financial information was computed as if the acquisition of the Newfield Properties had been completed on January 1, 2011. The financial information was derived from W&T’s audited historical consolidated financial statement for annual periods, W&T’s unaudited historical condensed consolidated financial statement for the interim period, the Newfield Properties’ audited historical financial statements for 2011 and the Newfield Properties’ unaudited historical financial statement for the 2012 interim period.

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

The pro forma adjustments were based on estimates by management and information believed to be directly related to the purchase of the Newfield Properties. The pro forma financial information is not necessarily indicative of the results of operations had the purchase occurred on January 1, 2011. If the transaction 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 Newfield; realized sales prices for oil, natural gas liquids (“NGLs”) and natural gas may have been different; and costs of operating the Newfield Properties may have been different. The following table presents a summary of our pro forma financial information (in thousands except earnings per share):

 

     Three Months Ended
March 31, 2012
 

Revenue

   $ 279,108   

Net income

     8,168   

Basic and diluted earnings per common share

     0.11   

For the pro forma financial information, certain information was derived from financial records and certain information was estimated. The sources of information and significant assumptions are described below:

 

  (a) Revenues and direct operating expenses for the Newfield Properties were derived from the historical financial records of Newfield. Incremental revenues and direct operating expenses for the three month period ended March 31, 2012 were $43.2 million and $11.3 million, respectively.

 

  (b) Incremental costs for insurance for the three month period ended March 31, 2012 were estimated at $0.2 million, which were derived from the incremental costs to add the Newfield Properties to W&T’s insurance programs. The direct operating expenses for the Newfield Properties described above excluded insurance costs.

 

  (c) DD&A was estimated using the full-cost method and determined as the incremental DD&A expense due to adding the Newfield Properties’ costs, reserves and production into our currently existing full cost pool in order to compute such amounts. The purchase price allocation included $13.1 million that was allocated to the pool of unevaluated properties for oil and natural gas interests. Accordingly, no DD&A expense was estimated for the unevaluated properties. ARO was estimated by W&T management. Incremental DD&A was estimated at $20.4 million for the three month period ended March 31, 2012.

 

  (d) The acquisition was assumed to be funded entirely with borrowed funds. Interest expense was computed using assumed borrowings of $205.6 million, which equates to the cash component of the transaction, and an interest rate of 7.7%, which equates to the effective yield on net proceeds for the additional senior notes issued shortly after the acquisition closed. Incremental interest expense was estimated at $4.0 million for the three month period ended March 31, 2012.

 

  (e) 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. Incremental capitalized interest was estimated at $0.2 million for the three month period ended March 31, 2012.

 

  (f) Income tax expense was computed using the 35% federal statutory rate. Incremental income tax expense was estimated at $2.7 million for the three month period ended March 31, 2012.

2012 Divestiture. On May 15, 2012, we sold our 40%, non-operated working interest in the South Timbalier 41 field located in the Gulf of Mexico for $30.5 million, net, with an effective date of April 1, 2012. The transaction was structured as a like-kind exchange under the Internal Revenue Service Code (“IRC”) Section 1031 and other applicable regulations, with funds held by a qualified intermediary until replacement purchases could be executed. Replacement purchases were consummated during 2012. In connection with this sale, we reversed $4.0 million of ARO.

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

3. Hurricane Remediation and Insurance Claims

During the third quarter of 2008, Hurricane Ike caused substantial damage to certain of our properties and we continue to incur costs and submit claims to our insurance underwriters related to repairing such damage. Our insurance policies in effect on the occurrence date of Hurricane Ike had a retention requirement of $10.0 million per occurrence, which has been satisfied, and coverage policy limits of $150.0 million for property damage due to named windstorms (excluding damage at certain facilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority.

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.

As of March 31, 2013, insurance receivables were $5.1 million and were included in Joint interest and other receivables on the balance sheet. As of December 31, 2012, no insurance receivables were recorded. From the third quarter of 2008 through March 31, 2013, we have received $142.2 million from our insurance underwriters related to Hurricane Ike. To the extent that additional remediation costs or plug and abandonment costs are incurred that are not covered by insurance, 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. See Note 4 for additional information about the impact of hurricane related items on our ARO. See Note 12 for information regarding legal actions taken by certain insurers and the Company.

4. Asset Retirement Obligations

Our ARO primarily represents 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 ARO is as follows (in thousands):

 

Balance, December 31, 2012

   $ 384,053   

Liabilities settled

     (23,464

Accretion of discount

     5,515   

Liabilities incurred

     131   

Revisions of estimated liabilities due to Hurricane Ike

     3,951   

Revisions of estimated liabilities – all other (1)

     8,039   
  

 

 

 

Balance, March 31, 2013

     378,225   

Less current portion

     69,964   
  

 

 

 

Long-term

   $ 308,261   
  

 

 

 

 

  (1) Revisions are primarily due to increases in the scope of work at several offshore locations required by the Bureau of Safety and Environmental Enforcement.

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. Our derivative instruments currently consist of crude oil swap and option contracts. All of the derivative counterparties are also lenders or affiliates of lenders participating in our revolving bank credit facility. We are exposed to credit loss in the event of nonperformance by the derivative counterparties; however, we currently anticipate that each of our derivative counterparties will be able to fulfill their contractual obligations.

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Additional collateral is not required by us due to the derivative counterparties’ collateral rights as lenders and we do not require collateral from our derivative counterparties. All of our current derivative agreements allow for netting of derivative gains and losses upon settlement. If an event of default were to occur causing an acceleration of payment under our revolving bank credit facility, that event may also trigger an acceleration of settlement of our derivative instruments. If we were required to settle all of our open derivative instruments, we would be able to net payments and receipts per counterparty pursuant to the derivative agreements.

We account for our 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. Although our derivative agreements allow for netting, which would allow for recording assets and liabilities per counterparty on a net basis, we account for our derivative contracts on a gross basis per contract as either an asset or liability. We have elected not to designate our commodity derivatives as hedging instruments; therefore, all changes in the fair value of derivative contracts are recognized currently in earnings. For additional information about fair value measurements, refer to Note 7.

Commodity Derivatives: We have entered into commodity swap contracts to manage a portion of our exposure to commodity price risk from sales of oil through December 2014. While these contracts are intended to reduce the effects of price volatility, they may also limit future income from favorable price movements. During the three months ended March 31, 2013 and 2012, our derivative contracts consisted entirely of crude oil contracts. The crude oil swap contracts are comprised of a portion based on West Texas Intermediate (“WTI”) crude oil prices and a portion based on Brent crude oil prices. The WTI based swaps are priced off the New York Mercantile Exchange, known as NYMEX. The Brent based swaps are priced off the Brent crude oil price quoted on the IntercontinentalExchange, known as ICE. Although our Gulf of Mexico crude oil is based off the WTI crude oil price plus a premium, the realized prices received for the types of crude oil have been closer to the Brent crude oil price because of competition with foreign supplied crude oil, which is based off the Brent crude oil price. Therefore, a portion of the swap oil contracts are priced off the Brent crude oil price to mitigate a portion of the price risk associated with our Gulf of Mexico crude oil production.

As of March 31, 2013, our open commodity derivatives were as follows:

 

     Swaps – Oil  
     Priced off Brent (ICE)      Priced off WTI (NYMEX)  

Termination Period

   Notional
Quantity (Bbls)
     Weighted
Average

Contract  Price
     Notional
Quantity (Bbls)
     Weighted
Average

Contract  Price
 

2013:     2nd quarter

     668,700       $ 106.48         244,000       $ 97.25   

              3rd quarter

     405,800         103.85         185,000         97.13   

              4th quarter

     294,400         101.98         520,000         97.38   

2014:     1st quarter

     180,000         97.38         59,000         97.02   

              2nd quarter

     172,900         97.38         —           —     

              3rd quarter

     165,600         97.38         —           —     

              4th quarter

     156,400         97.37         —           —     
  

 

 

       

 

 

    
     2,043,800       $ 102.30         1,008,000       $ 97.28   
  

 

 

       

 

 

    

Bbls = barrels

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

The following balance sheet line items included amounts related to the estimated fair value of our open derivative contracts as indicated in the following table (in thousands):

 

     March 31,
2013
     December 31,
2012
 

Prepaid and other assets

   $ 867       $ —     

Accrued liabilities

     6,938         6,355   

Other liabilities (noncurrent)

     2,427         3,046   

Changes in the fair value of our commodity derivative contracts are recognized currently in earnings and were as follows (in thousands):

 

     Three Months Ended
March 31,
 
     2013     2012  

Derivative (gain) loss:

    

Realized

   $ 4,271      $ 5,800   

Unrealized

     (903     33,834   
  

 

 

   

 

 

 

Total

   $ 3,368      $ 39,634   
  

 

 

   

 

 

 

6. Long-Term Debt

Our long-term debt was as follows (in thousands):

 

     March 31,
2013
     December 31,
2012
 

8.50% Senior Notes

   $ 900,000       $ 900,000   

Debt premiums, net of amortization

     17,079         17,611   

Revolving bank credit facility

     143,000         170,000   
  

 

 

    

 

 

 

Total long-term debt

     1,060,079         1,087,611   

Current maturities of long-term debt

     —          —    
  

 

 

    

 

 

 

Long-term debt, less current maturities

   $ 1,060,079       $ 1,087,611   
  

 

 

    

 

 

 

At March 31, 2013 and December 31, 2012, the balance outstanding of our senior notes, which bear an annual interest rate of 8.50% and mature on June 15, 2019 (the “8.50% Senior Notes”), was classified as long-term at their carrying value. Interest on the 8.50% Senior Notes is payable semi-annually in arrears on June 15 and December 15. The estimated annual effective interest rate on the 8.50% Senior Notes is 8.4%, which includes amortization of debt issuance costs and premiums. We are subject to various financial and other covenants under the indenture governing the 8.50% Senior Notes and we were in compliance with those covenants as of March 31, 2013.

The Fourth Amended and Restated Credit Agreement (the “Credit Agreement”) governs our revolving bank credit facility and terminates on May 5, 2015. Borrowings under our revolving bank credit facility are secured by our oil and natural gas properties. Availability under such facility is subject to a semi-annual redetermination of our borrowing base that occurs in the spring and fall of each year and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria.

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

At March 31, 2013 and December 31, 2012, we had $0.6 million of letters of credit outstanding under the revolving bank credit facility. The estimated annual effective interest rate was 3.7% for the three months ended March 31, 2013 for borrowings under the revolving bank credit facility. The estimated annual effective interest rate includes amortization of debt issuance costs and excludes commitment fees and other costs. As of March 31, 2013, our borrowing base was $725.0 million and our borrowing capacity availability was $581.4 million. See Note 13 for information on a subsequent increase of the borrowing base to $800.0 million.

Under the Credit Agreement, 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, each as defined in the Credit Agreement. We were in compliance with all applicable covenants of the Credit Agreement as of March 31, 2013.

For information about fair value measurements for our 8.50% Senior Notes and revolving bank credit facility, refer to Note 7.

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. The fair value of our 8.50% Senior Notes is based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2. The carrying amount of debt under our revolving bank credit facility approximates fair value because the interest rates are variable and reflective of market rates.

The following table presents the fair value of our derivative financial instruments, 8.50% Senior Notes and revolving bank credit facility for the periods indicated (in thousands).

 

            March 31, 2013      December 31, 2012  
      Hierarchy      Assets      Liabilities      Assets      Liabilities  

Derivatives

     Level 2       $ 867       $ 9,365       $  —         $ 9,401   

8.50% Senior Notes

     Level 2         —           976,500         —          963,000   

Revolving bank credit facility

     Level 2         —           143,000         —          170,000   

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 8.50% Senior Notes and revolving bank credit facility are reported in the balance sheet at their carrying value as described 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 2012 and in 2011, the Company granted restricted stock units (“RSUs”) to certain 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 achievement of certain predetermined criteria. The RSUs granted in 2012 (the “2012 RSUs”) were subject to performance criteria of earnings per share and total shareholder return (“TSR”), while the RSUs granted in 2011 (the “2011 RSUs”) were subject to only earnings per share performance measurement. In 2012 and in prior years, restricted stock was granted to the Company’s non-employee directors under the Director Compensation Plan. The restricted stock and RSUs each vest at the end of specified service periods. In addition to share-based compensation, the Company may grant to 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 are expected to actually vest.

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

At March 31, 2013, there were 1,393,602 shares of common stock available for issuance in satisfaction of awards under the Plan and 546,829 shares of common stock available for issuance in satisfaction of awards under the Director Compensation Plan. The shares available for both plans are reduced when restricted stock is granted. RSUs will reduce the shares available in the Plan only if RSUs are settled in shares of common stock. Although the Company has the option to settle RSUs in stock or cash at vesting, only common stock has been used to settle vested RSUs to date. See Note 13 regarding shareholder approval received on May 7, 2013 to increase the shares available for issuance in the Plan by 4,000,000 shares and to make certain other amendments to the Plan.

Restricted Stock. As of March 31, 2013, the Company had 43,687 unvested restricted shares outstanding, all of which were issued to the 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. The fair value of restricted stock was estimated by using the Company’s closing price on the grant date.

Subject to the satisfaction of service conditions, the outstanding restricted shares issued to the non-employee directors as of March 31, 2013 are expected to vest as follows:

 

     Shares  

2013 (1)

     27,297   

2014

     10,295   

2015

     6,095   
  

 

 

 

Total

     43,687   
  

 

 

 

 

  (1) Includes accelerated vesting of restricted shares held by one non-employee director who did not stand for re-election to the Board.

There were no grants, forfeitures or vesting of restricted shares during the three months ended March 31, 2013 and 2012.

Restricted Stock Units. As of March 31, 2013, the Company had outstanding RSUs issued to certain employees. A portion of the 2012 RSUs remains subject to the certain pre-defined performance measures of TSR for the defined periods in 2013 and 2014; therefore, this portion will be determined whether eligible for vesting at the end of the respective performance periods. TSR is determined based upon the change in the entity’s stock price and dividends for the performance period. The TSR targets are the ranking of the Company’s TSR compared to the TSR of 19 peer companies. The TSR components have an issuance scale from 0% to 150%. The portion of RSUs subject to TSR performance measurement is disclosed in the second table below.

The fair value for the 2012 RSUs was determined separately for the component related to the earnings per share targets and the component related to TSR targets. The fair value of the 2012 RSUs component related to earnings per share targets was determined using the Company’s closing price on the grant date. The fair value for the 2012 RSUs component related to TSR targets was determined by using a Monte Carlo simulation probabilistic model. The inputs used in the probabilistic model for the Company and the peer companies were: average closing stock prices during January 2012; risk-free interest rates using the London Interbank Offered Rate (“LIBOR”) ranging from 0.15% to 0.72% over the service period; expected volatilities ranging from 33% to 74%; expected dividend yields ranging from 0.0% to 2.5%; and correlation factors ranging from (67%) to 94%. The expected volatilities, expected dividends and correlation factors were developed using historical data. The fair value of the 2011 RSUs was estimated by using the Company’s closing price on the grant date.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

In addition to being subject to predetermined performance criteria, all RSUs are subject to service requirements prior to vesting. All RSUs awarded are subject to forfeiture until vested and cannot be sold, transferred or otherwise disposed of during the restricted period. Dividend equivalents are earned at the same rate as dividends paid on our common stock after achieving the specified performance requirement for that component of the RSUs.

A summary of activity related to RSUs is as follows:

 

     Restricted Stock Units  
     Units     Weighted Average
Grant Date Fair
Value Per Unit
 

Outstanding RSUs, December 31, 2012

     969,820      $ 22.70   

Granted (1)

     1,171        18.39   

Vested

     —          —     

Forfeited

     (11,293     19.26   
  

 

 

   

Outstanding RSUs, March 31, 2013

     959,698      $ 22.73   
  

 

 

   

 

  (1) Adjustments to amounts granted in 2012.

Subject to the satisfaction of service conditions, the RSUs outstanding as of March 31, 2013 are eligible to vest in December of the year indicated in the table below:

 

     Shares  

2013

     474,812   

2014

     344,288   

2014 (2)

     140,598   
  

 

 

 

Total

     959,698   
  

 

 

 

 

  (2) In addition to service requirements, these RSUs are also subject to certain performance requirements not yet measureable, with adjustments ranging from 0% to 150%.

During the three months ended March 31, 2012, there were no grants or vesting of RSUs.

Share-Based Compensation. A summary of incentive compensation expense under share-based payment arrangements and the related tax benefit is as follows (in thousands):

 

     Three Months Ended
March 31,
 
     2013      2012  

Share-based compensation expense from:

     

Restricted stock

   $ 99       $ 106   

Restricted stock units

     2,156         2,553   
  

 

 

    

 

 

 

Total

   $ 2,255       $ 2,659   
  

 

 

    

 

 

 

Share-based compensation tax benefit:

     

Tax benefit computed at the statutory rate

   $ 789       $ 931   
  

 

 

    

 

 

 

Unrecognized Share-Based Compensation. As of March 31, 2013, unrecognized share-based compensation expense related to our outstanding restricted shares and RSUs was $0.4 million and $9.2 million, respectively. Unrecognized share-based compensation expense will be recognized through April 2015 for restricted shares and November 2014 for RSUs.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Cash-Based Incentive Compensation. As defined by the Plan, annual incentive awards may be granted to eligible employees payable in cash. These awards are performance-based awards consisting of one or more business criteria or 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.

Share-Based Compensation and Cash-Based Incentive Compensation Expense. A summary of incentive compensation expense is as follows (in thousands):

 

     Three Months Ended
March 31,
 
     2013      2012  

Share-based compensation expense included in:

     

General and administrative

   $ 2,255       $ 2,659   
  

 

 

    

 

 

 

Total charged to operating income

     2,255         2,659   
  

 

 

    

 

 

 

Cash-based incentive compensation included in:

     

Lease operating expense

     1,393         1,900   

General and administrative

     3,530         1,878   
  

 

 

    

 

 

 

Total charged to operating income

     4,923         3,778   
  

 

 

    

 

 

 

Total incentive compensation charged to operating income

   $ 7,178       $ 6,437   
  

 

 

    

 

 

 

9. Income Taxes

Income tax expense of $14.9 million and $2.0 million was recorded during the three months ended March 31, 2013 and 2012, respectively. Our effective tax rate for the three months ended March 31, 2013 was 35.9% and differed from the federal statutory rate of 35.0% primarily as a result of state income taxes. Our effective tax rate for the three months ended March 31, 2012 was 38.1%, and differed from the federal statutory rate primarily as a result of the recapture of deductions for qualified domestic production activities under Section 199 of the IRC as a result of loss carrybacks to prior years. Income taxes receivables as of March 31, 2013 is comprised of $4.9 million of refunds related to 2012 estimated payments; $42.9 million of refunds related to tax loss carrybacks to 2010 and 2011; and partially offset by $2.2 million of accrued taxes payable related to 2013 alternative minimum tax.

As of March 31, 2013 and December 31, 2012, we did not have any unrecognized tax benefit recorded. As of March 31, 2013 and December 31, 2012, we had a valuation allowance related to state net operating losses. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or net operating losses are deductible. The tax years from 2009 through 2012 remain open to examination by the tax jurisdictions to which we are subject.

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

10. Earnings Per Share

The following table presents the calculation of basic and diluted earnings per common share (in thousands, except per share amounts):

 

     Three Months Ended
March 31,
 
     2013      2012  

Net income

   $ 26,618       $ 3,218   

Less portion allocated to nonvested shares

     281         140   
  

 

 

    

 

 

 

Net income allocated to common shares

   $ 26,337       $ 3,078   
  

 

 

    

 

 

 

Weighted average common shares outstanding

     75,206         74,300   
  

 

 

    

 

 

 

Basic and diluted earnings per common share

   $ 0.35       $ 0.04   

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

     870         1,765   

11. Dividends

During the three months ended March 31, 2013 and 2012, we paid regular cash dividends of $0.08 per common share each period. On May 7, 2013, our board of directors declared a cash dividend of $0.09 per common share, payable on June 4, 2013 to shareholders of record on May 24, 2013.

12. Contingencies

Cameron Parish Louisiana Claim. Since 2009, certain Cameron Parish landowners have filed suits in the 38th Judicial District Court, Cameron Parish, Louisiana against the Company and its Chief Executive Officer, Tracy W. Krohn, as well as several other defendants unrelated to us. In their lawsuits, plaintiffs alleged that property they own has been contaminated or otherwise damaged by the defendants’ oil and gas exploration and production activities and they are seeking compensatory and punitive damages. During 2012, we settled claims with certain landowners and paid $10.0 million. We assessed the remaining claims to be probable and have accrued $1.3 million in our contingent liabilities as of March 31, 2013 and December 31, 2012, of which one claim was settled in April 2013 for $0.5 million. However, we cannot state with certainty that our estimates of additional exposure are accurate concerning this matter.

Qui Tam Litigation. On September 21, 2012, the Company was served with a complaint in a qui tam action filed under the federal False Claims Act by an employee of a Company contractor. The lawsuit, United States ex rel. Comeaux v. W&T Offshore, Inc., et al.; CA No. 10-494, was filed in the United States District Court for the Eastern District of Louisiana, against the Company and three other working interest owners related to claims associated with three of the Company’s operated production platforms. A qui tam action, also known as a “whistleblower” action, is a lawsuit brought by a private citizen seeking civil penalties or damages against a person or company on behalf of the government for alleged violations of law. If the claims are successful, the person filing the suit may recover a percentage of the damages or penalty from the lawsuit as a reward for exposing a wrongdoing and recovering funds on behalf of the government. The complaint was originally filed in 2010 but kept under confidential seal in order for the federal government to decide if it wished to intervene and take over the prosecution of the qui tam action. The government declined to intervene in this suit and the complaint was unsealed and made public in June 2012, thereby giving the plaintiff the opportunity to pursue the claims on behalf of the government.

The complaint alleges that environmental violations at three of the Company’s operated production platforms in the Gulf of Mexico violate the federal offshore lease provisions so that the Company, among other things, wrongfully retained benefits under the applicable leases. The alleged environmental violations include allegations of discharges of relatively small amounts of oil into the Gulf of Mexico, the failure to report and record such discharges, and falsification of certain produced water samples and related reports required under federal law. The events are alleged to have occurred in 2009. These are largely the same underlying environmental allegations that resulted in the plea agreement described in the audited financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012. The Company has filed a motion to dismiss the plaintiff’s claims. The plaintiff dismissed his claims against the three other working interest owners after they filed motions to dismiss. The plaintiff conceded that certain of his claims should be dismissed in his reply to the Company’s motion to dismiss. The motion remains pending before the court.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

The Company intends to vigorously defend the claims made in this lawsuit. While the Company has determined that the likelihood of an adverse outcome may be reasonably possible, the range of potential loss cannot yet be estimated, and accordingly, no accrual has been made.

Insurance Claims. During the fourth quarter of 2012, underwriters of W&T’s excess liability policies (Indemnity Insurance Company of North America, New York Marine & General Insurance Company, Navigators Insurance Company, XL Specialty Insurance Company and Liberty Mutual Insurance Co.) filed declaratory judgment actions in the United States District Court for the Southern District of Texas seeking a determination that such policies do not cover removal of wreck and debris claims arising from Hurricane Ike that occurred in 2008. The court consolidated the various suits filed by the underwriters. W&T has not yet filed any claim under such excess policies, but W&T anticipates that such claims may reach $50.0 million in aggregate. In January 2013, the Company filed a motion for summary judgment seeking the court’s determination that such excess policies do in fact provide coverage for such removal of wreck and debris claims. The motion for summary judgment is pending. If the motion is successful, the Company expects to receive reimbursement for these costs once the claims are submitted. The Company has incurred $49.7 million to date in costs related to removal of wreck associated with platforms damaged by Hurricane Ike and expects to incur an additional $0.7 million. Removal of wreck costs are recorded in Oil and natural gas properties and equipment on the Balance Sheet. Any recoveries from claims made on these policies related to this issue will be recorded as reductions in this line item, which will reduce the Company’s DD&A rate and replenish our cash expenditures.

Royalties. In 2009, the Company recognized $5.3 million in allowable reductions of cash payments for royalties owed to the Office of Natural Resources Revenue (the “ONRR”) for transportation of their deepwater production through our subsea pipeline systems. In 2010, the ONRR audited the calculations and support related to this usage fee, and in the third quarter of 2010, we were notified that the ONRR had disallowed approximately $4.7 million of the reductions taken. We recorded a reduction to other revenue of $4.7 million in the third quarter of 2010 to reflect this disallowance; however, we disagree with the position taken by the ONRR and we are pursuing our claim to resolve the matter.

Other Claims. 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.

Contingent Liability Recorded. Recognized expenses related to accrued and settled claims, complaints and fines were zero for the three months ended March 31, 2013 and $8.3 million for the three months ended March 31, 2012. These expenses are reported in General and administrative expenses on the statement of income and reflect the items noted above and other various claims and complaints. As of March 31, 2013 and December 31, 2012, we have recorded a liability of $1.3 million, which is included in Accrued liabilities on the balance sheet, for the loss contingencies matters that include the events described above and other minor environmental and litigation matters which we are addressing in the normal course of business.

13. Subsequent Events

Effective April 19, 2013, the borrowing base and the amount available for borrowing under the revolving bank credit facility was increased to $800.0 million. There were no changes to the terms of the Credit Agreement, such as the maturity date, interest rates, covenants or collateral.

 

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W&T OFFSHORE, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

On May 7, 2013, at our annual shareholder meeting, our shareholders approved a proposal to increase the number of shares available for issuance in the Plan by 4,000,000 shares beyond the amount previously authorized and to extend the term of the Plan for an additional five years to April 15, 2019. This increase in shares reserved for issuance under the Plan is expected to be registered with the SEC within one month. The source of the shares to be issued as awards may come from authorized but unissued common stock or common stock held in the Company’s treasury, which was previously acquired by the Company in the open market. In addition, an amendment to the Plan was approved, which allows the Compensation Committee to take certain transactions, accounting or legal changes, and charges or certain other unusual items into account when determining whether performance goals that are applicable to performance awards under the Plan have been met.

14. Supplemental Guarantor Information

Our payment obligations under the Company’s outstanding 8.50% Senior Notes and the Credit Agreement (see Note 6) are fully and unconditionally guaranteed by certain of our wholly-owned subsidiaries, including W&T Energy VI, LLC and W&T Energy VII, LLC (together, the “Guarantor Subsidiaries”). W&T Energy VII, LLC does not currently have any active operations. Guarantees of the 8.50% Senior Notes will be released under certain circumstances, including:

(1) in connection with any sale or other disposition of all or substantially all of the assets of a Guarantor Subsidiary (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary (as such term is defined in the indenture governing the 8.50% Senior Notes) of the Company, if the sale or other disposition does not violate the “Asset Sales” provisions of the indenture;

(2) in connection with any sale or other disposition of the capital stock of such Guarantor Subsidiary to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, if the sale or other disposition does not violate the “Asset Sales” provisions of the indenture and the Guarantor Subsidiary ceases to be a subsidiary of the Company as a result of such sales or disposition;

(3) if such Guarantor Subsidiary is a Restricted Subsidiary and the Company designates such Guarantor Subsidiary as an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture;

(4) upon Legal Defeasance or Covenant Defeasance (as such terms are defined in the indenture) or upon satisfaction and discharge of the indenture;

(5) upon the liquidation or dissolution of such Guarantor Subsidiary, provided no event of default has occurred and is continuing; or

(6) at such time as such Guarantor Subsidiary is no longer required to be a Guarantor Subsidiary of the 8.50% Senior Notes as described in the indenture, provided no event of default has occurred and is continuing.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

The following unaudited condensed consolidating financial information presents the financial condition, results of operations and cash flows of W&T Offshore, Inc. (the “Parent Company”) and the Guarantor Subsidiaries, together with consolidating adjustments necessary to present the Company’s results on a consolidated basis.

Condensed Consolidating Balance Sheet as of March 31, 2013

 

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

Current assets:

         

Cash and cash equivalents

   $ 12,277      $ —         $ —        $ 12,277   

Receivables:

         

Oil and natural gas sales

     80,556        16,753         —          97,309   

Joint interest and other

     35,681        —           —          35,681   

Income taxes

     167,708        —           (122,070     45,638   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total receivables

     283,945        16,753         (122,070     178,628   

Deferred income taxes

     1,432        —           —          1,432   

Prepaid expenses and other assets

     22,363        —           —          22,363   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total current assets

     320,017        16,753         (122,070     214,700   

Property and equipment – at cost:

         

Oil and natural gas properties and equipment

     6,480,011        356,579         —          6,836,590   

Furniture, fixtures and other

     21,949        —           —          21,949   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total property and equipment

     6,501,960        356,579         —          6,858,539   

Less accumulated depreciation, depletion and amortization

     4,543,468        215,730         —          4,759,198   
  

 

 

   

 

 

    

 

 

   

 

 

 

Net property and equipment

     1,958,492        140,849         —          2,099,341   

Restricted deposits for asset retirement obligations

     29,161        —           —          29,161   

Deferred income taxes

     —          12,776         (12,776     —     

Other assets

     454,552        417,655         (853,352     18,855   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total assets

   $ 2,762,222      $ 588,033       $ (988,198   $ 2,362,057   
  

 

 

   

 

 

    

 

 

   

 

 

 
Liabilities and Shareholders’ Equity          

Current liabilities:

         

Accounts payable

   $ 112,207      $ 16       $ —        $ 112,223   

Undistributed oil and natural gas proceeds

     41,011        244         —          41,255   

Asset retirement obligations

     69,964        —           —          69,964   

Accrued liabilities

     38,676        122,461         (122,070     39,067   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total current liabilities

     261,858        122,721         (122,070     262,509   

Long-term debt

     1,060,079        —           —          1,060,079   

Asset retirement obligations, less current portion

     278,646        29,615         —          308,261   

Deferred income taxes

     171,698        —           (12,776     158,922   

Other liabilities

     425,942        —           (417,654     8,288   

Shareholders’ equity:

         

Common stock

     1        —           —          1   

Additional paid-in capital

     398,465        231,759         (231,759     398,465   

Retained earnings

     189,700        203,938         (203,939     189,699   

Treasury stock, at cost

     (24,167     —           —          (24,167
  

 

 

   

 

 

    

 

 

   

 

 

 

Total shareholders’ equity

     563,999        435,697         (435,698     563,998   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total liabilities and shareholders’ equity

   $ 2,762,222      $ 588,033       $ (988,198   $ 2,362,057   
  

 

 

   

 

 

    

 

 

   

 

 

 

 

18


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, 2012

 

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

Current assets:

         

Cash and cash equivalents

   $ 12,245      $ —         $ —        $ 12,245   

Receivables:

         

Oil and natural gas sales

     80,729        17,004         —          97,733   

Joint interest and other

     56,439        —           —          56,439   

Income taxes

     163,750        —           (115,866     47,884   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total receivables

     300,918        17,004         (115,866     202,056   

Deferred income taxes

     267        —           —          267   

Prepaid expenses and other assets

     25,555        —           —          25,555   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total current assets

     338,985        17,004         (115,866     240,123   

Property and equipment – at cost:

         

Oil and natural gas properties and equipment

     6,356,529        337,981         —          6,694,510   

Furniture, fixtures and other

     21,786        —           —          21,786   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total property and equipment

     6,378,315        337,981         —          6,716,296   

Less accumulated depreciation, depletion and amortization

     4,461,886        193,955         —          4,655,841   
  

 

 

   

 

 

    

 

 

   

 

 

 

Net property and equipment

     1,916,429        144,026         —          2,060,455   

Restricted deposits for asset retirement obligations

     28,466        —           —          28,466   

Deferred income taxes

     —          13,509         (13,509     —     

Other assets

     442,540        393,499         (816,096     19,943   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total assets

   $ 2,726,420      $ 568,038       $ (945,471   $ 2,348,987   
  

 

 

   

 

 

    

 

 

   

 

 

 
Liabilities and Shareholders’ Equity          

Current liabilities:

         

Accounts payable

   $ 123,792      $ 93       $ —        $ 123,885   

Undistributed oil and natural gas proceeds

     36,791        282         —          37,073   

Asset retirement obligations

     92,595        —           35        92,630   

Accrued liabilities

     20,755        116,132         (115,866     21,021   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total current liabilities

     273,933        116,507         (115,831     274,609   

Long-term debt

     1,087,611        —           —          1,087,611   

Asset retirement obligations, less current portion

     262,524        28,934         (35     291,423   

Deferred income taxes

     158,758        —           (13,509     145,249   

Other liabilities

     402,407        —           (393,499     8,908   

Shareholders’ equity:

         

Common stock

     1        —           —          1   

Additional paid-in capital

     396,186        231,759         (231,759     396,186   

Retained earnings

     169,167        190,838         (190,838     169,167   

Treasury stock, at cost

     (24,167     —           —          (24,167
  

 

 

   

 

 

    

 

 

   

 

 

 

Total shareholders’ equity

     541,187        422,597         (422,597     541,187   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total liabilities and shareholders’ equity

   $ 2,726,420      $ 568,038       $ (945,471   $ 2,348,987   
  

 

 

   

 

 

    

 

 

   

 

 

 

 

19


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 March 31, 2013

 

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

Revenues

   $ 209,528      $ 49,694       $ —        $ 259,222   
  

 

 

   

 

 

    

 

 

   

 

 

 

Operating costs and expenses:

         

Lease operating expenses

     54,529        4,812         —          59,341   

Production taxes

     1,789        —           —          1,789   

Gathering and transportation

     3,662        782         —          4,444   

Depreciation, depletion, amortization and accretion

     86,416        22,456         —          108,872   

General and administrative expenses

     19,604        1,483         —          21,087   

Derivative loss

     3,368        —           —          3,368   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total costs and expenses

     169,368        29,533         —          198,901   
  

 

 

   

 

 

    

 

 

   

 

 

 

Operating income

     40,160        20,161         —          60,321   

Earnings of affiliates

     13,100        —           (13,100     —     

Interest expense:

         

Incurred

     21,234        —           —          21,234   

Capitalized

     (2,433     —           —          (2,433
  

 

 

   

 

 

    

 

 

   

 

 

 

Income before income tax expense

     34,459        20,161         (13,100     41,520   

Income tax expense

     7,841        7,061         —          14,902   
  

 

 

   

 

 

    

 

 

   

 

 

 

Net income

   $ 26,618      $ 13,100       $ (13,100   $ 26,618   
  

 

 

   

 

 

    

 

 

   

 

 

 

Condensed Consolidating Statement of Income for the Three Months Ended March 31, 2012

 

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

Revenues

   $ 176,562      $ 59,324       $ —        $ 235,886   
  

 

 

   

 

 

    

 

 

   

 

 

 

Operating costs and expenses:

         

Lease operating expenses

     50,018        6,645         —          56,663   

Production taxes

     1,485        —           —          1,485   

Gathering and transportation

     3,484        737         —          4,221   

Depreciation, depletion, amortization and accretion

     67,623        20,868         —          88,491   

General and administrative expenses

     26,887        2,592         —          29,479   

Derivative loss

     39,634        —           —          39,634   
  

 

 

   

 

 

    

 

 

   

 

 

 

Total costs and expenses

     189,131        30,842         —          219,973   
  

 

 

   

 

 

    

 

 

   

 

 

 

Operating income (loss)

     (12,569     28,482         —          15,913   

Earnings of affiliates

     18,516        —           (18,516     —     

Interest expense:

         

Incurred

     13,905        —           —          13,905   

Capitalized

     (3,191     —           —          (3,191
  

 

 

   

 

 

    

 

 

   

 

 

 

Income (loss) before income tax expense

     (4,767     28,482         (18,516     5,199   

Income tax expense (benefit)

     (7,985     9,966         —          1,981   
  

 

 

   

 

 

    

 

 

   

 

 

 

Net income

   $ 3,218      $ 18,516       $ (18,516   $ 3,218   
  

 

 

   

 

 

    

 

 

   

 

 

 

 

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 Three Months Ended March 31, 2013

 

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

Operating activities:

        

Net income

   $ 26,618      $ 13,100      $ (13,100   $ 26,618   

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

        

Depreciation, depletion, amortization and accretion

     86,416        22,456        —          108,872   

Amortization of debt issuance costs and premium

     447        —          —          447   

Share-based compensation

     2,255        —          —          2,255   

Derivative loss

     3,368        —          —          3,368   

Cash payments on derivative settlements

     (4,271     —          —          (4,271

Deferred income taxes

     11,774        733        —          12,507   

Earnings of affiliates

     (13,100     —          13,100        —     

Changes in operating assets and liabilities:

        

Oil and natural gas receivables

     172        251        —          423   

Joint interest and other receivables

     25,875        —          —          25,875   

Income taxes

     (3,957     6,329        —          2,372   

Prepaid expenses and other assets

     4,911        (24,155     24,155        4,911   

Asset retirement obligation settlements

     (23,311     (153     —          (23,464

Accounts payable, accrued liabilities and other

     34,191        (115     (24,155     9,921   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     151,388        18,446        —          169,834   
  

 

 

   

 

 

   

 

 

   

 

 

 

Investing activities:

        

Investment in oil and natural gas properties and equipment

     (118,180     (18,446     —          (136,626

Purchases of furniture, fixtures and other

     (114     —          —          (114
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (118,294     (18,446     —          (136,740
  

 

 

   

 

 

   

 

 

   

 

 

 

Financing activities:

        

Borrowings of long-term debt – revolving bank credit facility

     112,000        —          —          112,000   

Repayments of long-term debt – revolving bank credit facility

     (139,000     —          —          (139,000

Dividends to shareholders

     (6,020     —          —          (6,020

Other

     (42     —          —          (42
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash used in financing activities

     (33,062     —          —          (33,062
  

 

 

   

 

 

   

 

 

   

 

 

 

Increase in cash and cash equivalents

     32        —          —          32   

Cash and cash equivalents, beginning of period

     12,245        —          —          12,245   
  

 

 

   

 

 

   

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 12,277      $ —        $ —        $ 12,277   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

21


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 Three Months Ended March 31, 2012

 

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

Operating activities:

        

Net income

   $ 3,218      $ 18,516      $ (18,516   $ 3,218   

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

        

Depreciation, depletion, amortization and accretion

     67,623        20,868        —          88,491   

Amortization of debt issuance costs

     586        —          —          586   

Share-based compensation

     2,659        —          —          2,659   

Derivative loss

     39,634        —          —          39,634   

Cash payments on derivative settlements

     (5,800     —          —          (5,800

Deferred income taxes

     2,963        (413     —          2,550   

Earnings of affiliates

     (18,516     —          18,516        —     

Changes in operating assets and liabilities:

        

Oil and natural gas receivables

     8,187        1,329        —          9,516   

Joint interest and other receivables

     (2,170     —          —          (2,170

Insurance receivables

     715        —          —          715   

Income taxes

     (20,766     10,380        —          (10,386

Prepaid expenses and other assets

     3,735        (37,855     38,004        3,884   

Asset retirement obligation settlements

     (5,384     —          —          (5,384

Accounts payable, accrued liabilities and other

     40,556        (1,908     (38,004     644   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     117,240        10,917        —          128,157   
  

 

 

   

 

 

   

 

 

   

 

 

 

Investing activities:

        

Investment in oil and natural gas properties and equipment

     (73,709     (10,917     —          (84,626

Purchases of furniture, fixtures and other

     (500     —          —          (500
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (74,209     (10,917     —          (85,126
  

 

 

   

 

 

   

 

 

   

 

 

 

Financing activities:

        

Borrowings of long-term debt – revolving bank credit facility

     84,000        —          —          84,000   

Repayments of long-term debt – revolving bank credit facility

     (117,000     —          —          (117,000

Dividends to shareholders

     (5,948     —          —          (5,948

Other

     (87     —          —          (87
  

 

 

   

 

 

   

 

 

   

 

 

 

Net cash used in financing activities

     (39,035     —          —          (39,035
  

 

 

   

 

 

   

 

 

   

 

 

 

Increase in cash and cash equivalents

     3,996        —          —          3,996   

Cash and cash equivalents, beginning of period

     4,512        —          —          4,512   
  

 

 

   

 

 

   

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 8,508      $ —        $ —        $ 8,508   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

22


Table of Contents
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 of 1934, which 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. Known material risks that may affect our financial condition and results of operations are discussed in Item 1A “Risk Factors” and market risks are discussed in Item 7A “Quantitative and Qualitative Disclosures About Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2012 and may be discussed or updated from time to time in subsequent reports filed with the SEC. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. 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 with operations offshore in the Gulf of Mexico and onshore in both the Permian Basin of West Texas and in East Texas. We have grown through acquisitions, exploration and development and currently hold working interests in approximately 72 producing offshore fields in federal and state waters (69 producing and three fields capable of producing). We currently have under lease approximately 1.4 million gross acres including approximately 0.7 million gross acres on the Gulf of Mexico Shelf, approximately 0.5 million gross acres in the deepwater and approximately 0.2 million gross acres onshore in Texas. A substantial majority of our daily production is derived from wells we operate offshore. In managing our business, we are concerned primarily with maximizing return on shareholders’ equity. To accomplish this primary goal, we focus on profitably increasing production and finding oil and gas reserves at a favorable cost. We strive to grow our reserves and production through acquisitions and our drilling programs. We have focused on acquiring properties where we can develop an inventory of drilling prospects that will enable us to continue to add reserves post-acquisition.

Our financial condition, cash flow and results of operations are significantly affected by the volume of our oil, NGLs and natural gas production and the prices that we receive for such production. Our production volumes for the first quarter of 2013 were comprised of approximately 41.0% oil and condensate, 11.9% NGLs and 47.1% natural gas, determined using the energy equivalency ratio of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil, condensate or NGLs. The conversion ratio does not assume price equivalency, and the price per one thousand cubic feet equivalent (“Mcfe”) for oil, NGLs and natural gas may differ significantly. In the first quarter of 2013, revenues from the sale of oil and NGLs made up 83.3% of our total revenues, compared to 83.2% in the first quarter of 2012. For the first quarter of 2013, our combined total production of oil, condensate, NGLs and natural gas was approximately 0.4% higher on a Mcfe basis than during the same period in 2012.

In October 2012, we acquired from Newfield certain oil and gas leasehold interests in the Gulf of Mexico. The Newfield Properties consist of leases covering 78 federal offshore blocks on approximately 416,000 gross acres (268,000 net acres) (excluding overriding royalty interests), comprised of 65 blocks in the deepwater, six of which are producing, 10 blocks on the conventional shelf, four of which are producing, and an overriding royalty interest in three deepwater blocks, two of which are producing. Internal estimates of proved reserves associated with the Newfield Properties as of the acquisition date were approximately 7.0 million barrels of oil equivalent (“MMBoe”) (42.0 billion cubic feet equivalent (“Bcfe”)), comprised of approximately 61% natural gas, 36% oil and 3% NGLs, all of which were classified as proved developed. Including adjustments from an effective date of July 1, 2012, the adjusted purchase price was $205.6 million and we assumed the ARO associated with the Newfield Properties, which we have estimated to be $31.7 million. The acquisition was initially funded from borrowings under our revolving bank credit facility and cash on hand. Subsequently in the same month, the amounts borrowed under our revolving bank credit facility were paid down with funds provided from the issuance of an additional $300.0 million of 8.50% Senior Notes.

 

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During the first quarter of 2013, our realized oil sales price (unhedged) decreased 2.9%, compared to the first quarter of 2012. Two comparable benchmarks are the unweighted average daily posted spot price of WTI crude oil, which decreased 8.4% from the comparable period, and the unweighted average daily posted spot price of Brent crude oil, which decreased 5.3% from the comparable period. WTI is frequently used to value domestically produced crude oil, and the majority of our oil production is priced using the spot price for WTI as a base price plus a premium depending on the type of crude oil. Most of our oil production is from our offshore production, which is comprised of various crudes including Heavy Louisiana Sweet, Light Louisiana Sweet, Poseidon and others. Starting in the first quarter of 2011 and continuing through the first quarter of 2013, these various crudes sold at a significant premium relative to WTI. During the first quarter of 2013, premiums for Heavy Louisiana Sweet crude and Light Louisiana Sweet crude ranged between $18.00 and $22.00 per barrel higher than WTI. During the first quarter of 2012, premiums for Heavy Louisiana Sweet crude and Light Louisiana Sweet crude ranged between $10.00 and $19.00 per barrel. The average premium spread prior to 2011 was approximately $2.00 to $3.00 per barrel. We may continue to experience higher premiums to WTI crude in our future sales of crude oil. We cannot predict how long such pricing conditions will last.

A possible cause cited by industry publications for the premiums afforded our offshore crudes is an oversupply situation at Cushing, Oklahoma, a primary domestic hub for crude oil priced using the WTI benchmark. Citing the Cushing crude over supply situation, the owners of the Seaway pipeline reversed the flow of crude oil in June 2012 to flow crude from Cushing to Freeport, Texas. In January 2013, the Seaway pipeline capacity was increased from 150,000 barrels per day to 400,000 barrels per day. Although this change increased the amount of crude oil available to Gulf Coast refineries, we did not experience a decline in premiums in the first quarter of 2013. The owners of the Seaway pipeline have announced plans to construct a parallel pipeline to be completed in the first quarter of 2014, which is expected to increase the capacity to 850,000 barrels per day. Other pipeline projects are underway that, when added to the Seaway pipeline capacity, could bring 1.9 million barrels per day of mid-continent crude oil to the Gulf Coast. That capacity is expected to grow to 2.4 million barrels per day by the end of 2014. We believe these actions may reduce the oversupply situation at Cushing, which may affect the premiums we receive on our offshore oil production.

Oil prices are affected by world events, such as political unrest in the Middle East, the threat of hostilities, demand changes in various countries and world economic growth. Some commentators believe world economic growth, which is currently being affected by the economies of China, Brazil, India and Russia, may support strong crude oil prices in the long term, although prices may deteriorate due to slower growth in China and softening of economies in other countries.

Notwithstanding these long-term views, crude oil prices will likely continue to be volatile. For the first quarter of 2013, WTI crude oil prices ranged from $90.00 to $98.00 per barrel and Brent crude oil prices ranged from $106.00 to $119.00 per barrel. The U.S. Energy Information Administration (“EIA”) estimates that global consumption outpaced global production during the first quarter of 2013. For the full year of 2013, EIA projects global consumption to be higher than production, and expect the situation to reverse in 2014 with production being higher the consumption. China is expected to be the leading contributor to consumption growth in 2013. North America’s production growth is expected to be partially offset by anticipated reductions from the Organization of the Petroleum Exporting Countries in 2013. Even though EIA projects global demand above global supply in 2013, EIA projects WTI average prices for 2013 to be approximately flat to 2012 and projects Brent average prices for 2013 to be below 2012 by approximately 4%. The new pipeline capacity for moving mid-continent crude to the Gulf Coast refineries was noted by EIA as being the primary rationale behind the lower Brent prices projected for 2013. Not only is pipeline capacity increasing, but rail receiving capacity on both the Gulf Coast and East Coast will allow crude to be shipped to the coastal refineries and may have the effect of narrowing the Brent to WTI differential.

Our average realized NGLs sales prices (unhedged) decreased 29.4% during the first quarter of 2013 compared to the first quarter of 2012. According to industry sources, increased domestic NGLs production has been the primary factor affecting price realizations. During the first quarter of 2013, prices for domestic ethane and propane, two common NGL components, decreased 50% and 31%, respectively, from the comparable period in 2012 and other domestic NGLs prices decreased between 6% and 20%. As long as ethane and propane inventories continue to be high and NGLs production continues to be high, we would expect prices for NGLs to be weak. In addition, as long as the crude to natural gas price ratio remains wide, NGLs production may continue to be high, which would continue to put downward pressure on the entire NGLs stream. Many natural gas processing facilities are re-injecting ethane back into the natural gas stream after processing due to increasing ethane supplies. This in turn increases natural gas supplies and has negatively impacted natural gas pricing.

 

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Natural gas prices are more affected by domestic issues (as compared to crude oil prices), such as weather (particularly extreme heat or cold), supply, local demand issues and domestic economic conditions, and they have historically been subject to substantial fluctuation. During the first quarter of 2013, the average realized sales price for our natural gas production increased 26.6% from the comparable period in 2012 to $3.38 per Mcf. A comparable benchmark is the Henry Hub unweighted average daily posted spot price, which increased 43.0% from the comparable period. Although the price has increased significantly on a percentage basis, the price is still weak from an overall economic standpoint and we expect continued weakness in natural gas prices for a number of reasons, including (i) producers continuing to drill in order to secure and to hold large lease positions before expiration, particularly in shale and similar resource plays, (ii) natural gas storage levels building during the injection season, (iii) natural gas continuing to be produced as a by-product in conjunction with the high level of oil drilling, (iv) increasing availability of liquefied natural gas, (v) production efficiency gains are achieved in the shale gas areas resulting from better hydraulic fracturing, horizontal drilling and production techniques and (vi) re-injecting ethane into the natural gas stream as indicated above which increases the natural gas supply. Per EIA, natural gas working inventories ended March 2013 were 30% below the level at the same time a year ago and 2% below the five-year average due in part to March 2013 being colder than expected. EIA expects the Henry Hub gas spot price, which averaged $2.75 per British thermal unit (MMBtu) in 2012, will average $3.52 per MMBtu in 2013 and $3.60 per MMBtu in 2014. EIA projects U.S. consumption to be slightly higher than production for both 2013 and 2014 by approximately 1%, which would lower inventories but not sufficiently enough to raise prices. According to Baker Hughes, the natural gas rig count at the end of the first quarter of 2013 is down approximately 42% compared to the end of the first quarter of 2012. With actual and forecasted natural gas prices being above comparable 2012 periods, EIA expects some U.S. energy producers to switch to coal-powered energy from natural gas during 2013. Industry sources have indicated that a natural gas price above $4.50 per Mcf will probably cause power producers to switch back to coal from natural gas, which in effect creates limits to how far natural gas prices can rise until such time as demand for natural gas increases from other sources.

Should prices decline for oil, NGLs and natural gas in the future, it would negatively impact our future oil, NGLs 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, reductions in proved reserves, issues with financial ratio compliance, and a reduction of the borrowing base associated with our Credit Agreement, depending on the severity of such declines. If any of these events 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.

There continues to be many proposed changes in laws, regulations, guidance and policy in our industry. The process for obtaining offshore drilling permits, especially deepwater drilling permits, has expanded and lengthened in the past few years. The most significant regulation changes in recent years are regulations related to potential environmental impacts, 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 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.

 

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Results of Operations

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

 

      Three Months Ended
March 31,
 
      2013(1)      2012      Change     %  
     (In thousands, except percentages and per share data)  

Financial:

          

Revenues:

          

Oil

   $ 197,564       $ 169,974       $ 27,590        16.2

NGLs

     18,327         26,384         (8,057     (30.5 )% 

Natural gas

     42,937         38,436         4,501        11.7

Other

     394         1,092         (698     (63.9 )% 
  

 

 

    

 

 

    

 

 

   

 

 

 

Total revenues

     259,222         235,886         23,336        9.9

Operating costs and expenses:

          

Lease operating expenses

     59,341         56,663         2,678        4.7

Production taxes

     1,789         1,485         304        20.5

Gathering and transportation

     4,444         4,221         223        5.3

Depreciation, depletion, amortization and accretion

     108,872         88,491         20,381        23.0

General and administrative expenses

     21,087         29,479         (8,392     (28.5 )% 

Derivative loss

     3,368         39,634         (36,266     (91.5 )% 
  

 

 

    

 

 

    

 

 

   

 

 

 

Total costs and expenses

     198,901         219,973         (21,072     (9.6 )% 
  

 

 

    

 

 

    

 

 

   

 

 

 

Operating income

     60,321         15,913         44,408        279.1

Interest expense, net of amounts capitalized

     18,801         10,714         8,087        75.5
  

 

 

    

 

 

    

 

 

   

 

 

 

Income before income tax expense

     41,520         5,199         36,321        698.6

Income tax expense

     14,902         1,981         12,921        652.2
  

 

 

    

 

 

    

 

 

   

 

 

 

Net income

   $ 26,618       $ 3,218       $ 23,400        727.2
  

 

 

    

 

 

    

 

 

   

 

 

 

Basic and diluted earnings per common share

   $ 0.35       $ 0.04       $ 0.31        775.0

 

  (1) In the fourth quarter of 2012, we acquired the Newfield Properties.

 

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      Three Months Ended
March 31,
 
      2013(1)      2012      Change     %  

Operating:

          

Net sales volumes:

          

Oil (MBbls)

     1,844         1,540         304        19.7

NGLs (MBbls)

     535         544         (9     (1.7 )% 

Natural gas (MMcf)

     12,720         14,376         (1,656     (11.5 )% 

Total oil equivalent (MBoe) (2)

     4,499         4,480         19        0.4

Total natural gas equivalent (MMcfe) (2)

     26,993         26,877         116        0.4

Average daily equivalent sales (Boe/d) (2)

     49,988         49,226         762        1.5

Average daily equivalent sales (Mcfe/d) (2)

     299,928         295,354         4,574        1.5

Average realized sales prices (Unhedged):

          

Oil ($/Bbl)

   $ 107.15       $ 110.39       $ (3.24     (2.9 )% 

NGLs ($/Bbl)

     34.25         48.51         (14.26     (29.4 )% 

Natural gas ($/Mcf)

     3.38         2.67         0.71        26.6

Oil equivalent ($/Boe) (2)

     57.53         52.41         5.12        9.8

Natural gas equivalent ($/Mcfe) (2)

     9.59         8.74         0.85        9.7

Average realized sales prices (Hedged) (3):

          

Oil ($/Bbl)

   $ 104.83       $ 106.63       $ (1.80     (1.7 )% 

NGLs ($/Bbl)

     34.25         48.51         (14.26     (29.4 )% 

Natural gas ($/Mcf)

     3.38         2.67         0.71        26.6

Oil equivalent ($/Boe) (2)

     56.58         51.12         5.46        10.7

Natural gas equivalent ($/Mcfe) (2)

     9.43         8.52         0.91        10.7

Average per Mcfe ($/Mcfe) (2):

          

Lease operating expenses

   $ 2.20       $ 2.11       $ 0.09        4.3

Gathering and transportation

     0.16         0.16         —          —  
  

 

 

    

 

 

    

 

 

   

 

 

 

Production costs

     2.36         2.27         0.09        4.0

Production taxes

     0.07         0.05         0.02        40.0

Depreciation, depletion, amortization and accretion

     4.03         3.29         0.74        22.5

General and administrative expenses

     0.78         1.10         (0.32     (29.1 )% 
  

 

 

    

 

 

    

 

 

   

 

 

 
   $ 7.24       $ 6.71       $ 0.53        7.9
  

 

 

    

 

 

    

 

 

   

 

 

 

Total number of wells drilled (gross):

          

Offshore

     2         —           2        N/A   

Onshore

     14         18         (4     (22.2 )% 

Total number of productive wells drilled (gross):

          

Offshore

     1         —           1        N/A   

Onshore

     14         18         (4     (22.2 )% 

 

  (1) In the fourth quarter of 2012, we acquired the Newfield Properties.
  (2) The conversion to barrels of oil equivalent and cubic feet equivalent were determined using the energy equivalency ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs (totals may not compute due to rounding). The conversion ratio does not assume price equivalency, and the price on an equivalent basis for oil, NGLs and natural gas may differ significantly.
  (3) Data for all periods presented includes the effects of realized gains and losses on commodity derivative contracts, none of which qualified for hedge accounting.

Volume measurements:

 

Boe - barrel of oil equivalent    MMcf - million cubic feet
Boe/d - barrel of oil equivalent per day    MMcfe - million cubic feet equivalent
MBbls - thousand barrels for crude oil, condensate or NGLs    Mcfe/d - thousand cubic feet equivalent per day
MBoe - thousand barrels of oil equivalent   

N/A = percentage change not applicable

 

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Three Months Ended March 31, 2013 Compared to the Three Months Ended March 31, 2012

Revenues. Total revenues increased $23.3 million to $259.2 million for the first quarter of 2013 as compared to the same period in 2012. Oil revenues increased $27.6 million, NGLs revenues decreased $8.1 million, natural gas revenues increased $4.5 million and other revenues decreased $0.7 million. The oil revenue increase was attributable to a 19.7% increase in sales volumes, partially offset by a 2.9% decrease in the average realized sales price (unhedged) to $107.15 per barrel for the first quarter of 2013 from $110.39 per barrel for the prior year period. The sales volume increase for oil was primarily attributable to increased production at Ship Shoal 349, the Newfield Properties acquired in 2012 and onshore properties in West Texas. These increases for oil production were partially offset by natural production declines in various fields. The NGLs revenue decrease was attributable to a 29.4% decrease in the average realized sales price (unhedged) to $34.25 per barrel for the first quarter of 2013 from $48.51 per barrel for the prior year period and a decrease of 1.7% in sales volumes from the comparable period. The sales volume decrease for NGLs was primarily attributable to pipeline and platform outages, natural production declines, individual well performances and the sale of South Timbalier 41 in 2012; and was partially offset by production from the Newfield Properties acquired in 2012 and new wells. The increase in natural gas revenue resulted from a 26.6% increase in the average realized natural gas sales price (unhedged) to $3.38 per Mcf in the first quarter of 2013 from $2.67 per Mcf for the prior year period, partially offset by a 11.5% decrease in sales volumes from the comparable period. The sales volume decrease for natural gas was primarily attributable to pipeline and platform outages, natural production declines, individual well performances and the sale of South Timbalier 41; and was partially offset by production from the Newfield Properties acquired in 2012 and increases at Ship Shoal 349. Revenues from oil and liquids as a percent of our total revenues were approximately the same, 83.3% for the first quarter of 2013 compared to 83.2% for the prior year period. NGLs realized prices as a percent of oil realized prices decreased to 32.0% for the first quarter of 2013 compared to 43.9% for the comparable period.

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 $2.7 million to $59.3 million in the first quarter of 2013 compared to the prior year period. On a per Mcfe basis, lease operating expenses increased to $2.20 per Mcfe during the first quarter 2013 compared to $2.11 per Mcfe during the comparable 2012 period. On a component basis, facilities, base lease operating expenses and hurricane remediation costs net of insurance claims increased $3.3 million, $0.6 million and $0.3 million respectively. As a partial offset, workover expense decreased $1.5 million. Insurance premiums were approximately flat between periods. The increase in facilities expense was attributable to numerous activities at multiple locations, with no one activity causing a substantial portion of the increase. The activities included sandblasting/painting, repairs, underwater inspection and installations of temporary equipment. The increase in base lease operating expenses is primarily attributable to the Newfield Properties acquired in 2012, partially offset by increased fees received from third parties for product handling. Workover expense decreases were primarily attributable to expenses incurred in 2012 related to an onshore well.

Production taxes. Production taxes increased to $1.8 million in the first quarter of 2013 compared to $1.5 million in the prior year period primarily due to onshore activities and are currently not a large component of our operating costs. Most of our production is from federal waters where no production taxes are imposed, whereas onshore operations are subject to production taxes.

Gathering and transportation costs. Gathering and transportation costs increased $0.2 million for the first quarter of 2013 compared to the prior year period.

Depreciation, depletion, amortization and accretion. DD&A, including accretion for ARO, increased to $4.03 per Mcfe for the first quarter of 2013 from $3.29 per Mcfe in the prior year period. On a nominal basis, DD&A increased to $108.9 million for the first quarter of 2013 from $88.5 million in the prior year period. DD&A on a per Mcfe basis and nominal basis increased primarily due to cost capitalized to the full cost pool from both the unevaluated pool and from increases in our ARO estimates without a corresponding increase in proved reserves, which primarily occurred in the latter part of 2012. In addition, our incurred development costs during 2012 were above estimates, we increased estimates of future development costs at year end 2012 and the Newfield Properties acquired in 2012 increased the DD&A on a per Mcfe basis.

General and administrative expenses. G&A decreased to $21.1 million for the first quarter of 2013 from $29.5 million for the prior year period primarily due to no litigation settlement expense recorded in the first quarter of 2013 compared to an $8.3 million litigation accrual recorded in the prior year period. G&A on a per Mcfe basis was $0.78 per Mcfe for the first quarter of 2013, compared to $1.10 per Mcfe for the prior year period.

 

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Derivative loss. For the first quarter of 2013 and 2012, our derivative net losses were $3.4 million and $39.6 million, respectively, and relate to the change in the fair value of our crude oil commodity derivatives as a result of changes in crude oil prices. Although the contracts relate to production for the current year and next year, changes in the fair value for all open contracts are recorded currently. For the first quarter of 2013, the net loss was comprised of a $4.3 million realized loss and a $0.9 million unrealized gain. For the first quarter of 2012, $5.8 million of the loss was realized and $33.8 million was unrealized. For additional information about our derivatives, refer to Item 1 Financial Statements – Note 5 – Derivative Financial Instruments.

Interest expense. Interest expense incurred increased to $21.2 million for the first quarter of 2013 from $13.9 million for the prior year period. The aggregate principal amount of our 8.50% Senior Notes outstanding was $900.0 million in the first quarter of 2013 compared to $600.0 million in the prior year period due to the issuance of 8.50% Senior Notes during October 2012. During the first quarter of 2013 and 2012, $2.4 million and $3.2 million, respectively, of interest was capitalized to unevaluated oil and natural gas properties. The decrease is primarily attributable to reclassifying unevaluated properties to the full cost pool during the fourth quarter of 2012.

Income tax expense. Income tax expense increased to $14.9 million for the first quarter of 2013 compared to $2.0 million for the same period of 2012. The increase is primarily attributable to the change in pre-tax income. Our effective tax rate for the three months ended March 31, 2013 was 35.9% and differed from the federal statutory rate of 35.0% primarily as a result of state income taxes. Our effective tax rate for the three months ended March 31, 2012 was 38.1% and differed from the federal statutory rate of 35.0% primarily as a result of the recapture of deductions for qualified domestic production activities under Section 199 of the IRC as a result of loss carrybacks to 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 and pay dividends. We have funded such activities with cash on hand, cash provided by operating activities, 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 first quarter of 2013 was $169.8 million compared to $128.2 million for the first quarter of 2012. The change was primarily due to higher revenues associated with increased production volumes for oil, increases in prices for natural gas, collections on joint interest receivables and lower income tax payments, partially offset by higher payments related to ARO. Our combined average realized sales price (hedged) per Mcfe was 10.7% higher than the comparable 2012 period due to oil increasing from 34% to 41% of our combined production and higher natural gas prices. Our combined production of oil, NGLs and natural gas on a Mcfe basis during the first quarter of 2013 was slightly higher than the first quarter of 2012.

Net cash used in investing activities during the first quarter of 2013 and 2012 was $136.7 million and $85.1 million, respectively, which represents our investments in both offshore and onshore oil and gas properties. The increase is primarily attributable to an increase in offshore drilling activity. There were no acquisitions completed in either period.

Net cash used in financing activities was $33.1 million and $39.0 million during the first quarter of 2013 and 2012, respectively. The cash used in the first quarter of 2013 and 2012 was attributable to net pay downs on the revolving bank credit facility and dividend payments.

At March 31, 2013, we had a cash balance of $12.3 million and $581.4 million of undrawn capacity available under the revolving bank credit facility, which had a borrowing base of $725.0 million as of March 31, 2013. See Financial Statements – Note 13 – Subsequent Events under Part I, Item 1 of this Form 10-Q describing an increase in our borrowing base to $800.0 million effective in April 2013.

Credit Agreement and long-term debt. At March 31, 2013 and December 31, 2012, $143.0 million and $170.0 million, respectively, were outstanding under our revolving bank credit facility. During the three months ended March 31, 2013, the outstanding borrowings on our revolving bank credit facility ranged from $143.0 million to $218.0 million. At March 31, 2013 and December 31, 2012, $900.0 million in aggregate principal amount of our 8.50% Senior Notes was outstanding. 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, but additional financing could be required if we are successful in finding suitable acquisitions. 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.

 

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Availability under our revolving bank credit facility is subject to a semi-annual redetermination of our borrowing base that occurs in the spring and fall of each year and is calculated by our lenders based on their evaluation of our proved reserves and their own internal criteria. 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 and all applicable covenants related to the 8.50% Senior Notes as of March 31, 2013.

Derivatives. 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 loan facility. As of March 31, 2013, our derivative instruments outstanding consisted of oil contracts relating to approximately 2.3 million barrels (“MMBbls”) and 0.7 MMBbls of our anticipated production for the balance of 2013 and the year 2014, respectively. See Financial Statements – Note 5– Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

Hurricane Remediation, Insurance Claims and Insurance. During the third quarter of 2008, Hurricane Ike caused substantial property damage and we continue to incur costs and submit claims to our insurance underwriters related to repairing such damage. Our insurance policies in effect on the occurrence date of Hurricane Ike had a retention requirement of $10.0 million per occurrence, which has been satisfied, and coverage policy limits of $150.0 million for property damage due to named windstorms (excluding damage at certain facilities) and $250.0 million for, among other things, removal of wreckage if mandated by any governmental authority.

Through March 2013, we have received cash from our insurance carrier related to Hurricane Ike claims totaling $142.2 million and have $5.1 million of insurance receivables recorded as of March 31, 2013 for claims that have been submitted and approved for payment. As of March 31, 2013, we have recorded in ARO an estimate of $6.4 million for additional costs to be incurred related to Hurricane Ike and we have estimated that this work will be completed by the end of 2013. We expect to receive reimbursement for a portion of these costs once costs are incurred and claims submitted. In addition, we have incurred removal of wreck costs related to Hurricane Ike, but some of our insurance carriers are disputing whether such costs are covered costs. Should necessary future expenditures exceed our insurance coverage for damages incurred as a result of Hurricane Ike, or claims are denied or there are significant delays in recovering further claims 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.

During the fourth quarter of 2012, underwriters of our excess liability policies (Indemnity Insurance Company of North America, New York Marine & General Insurance Company, Navigators Insurance Company, XL Specialty Insurance Company and Liberty Mutual Insurance Co.) filed declaratory judgment actions in the United States District Court for the Southern District of Texas seeking a determination that such policies do not cover removal of wreck and debris claims arising from Hurricane Ike that occurred in 2008. The court consolidated the various suits filed by underwriters. We have not yet filed any claim under such excess policies, but we anticipate that such claims may reach $50.0 million in aggregate. In January 2013, we filed a motion for summary judgment seeking the court’s determination that such excess policies do in fact provide coverage for such removal of wreck and debris claims. The motion for summary judgment is pending. If the motion is successful, we expect to receive reimbursement for these costs once the claims are submitted. We have incurred $49.7 million to date in costs related to removal of wreck associated with platforms damaged by Hurricane Ike and expect to incur an additional $0.7 million. Removal of wreck costs are recorded in Oil and natural gas properties and equipment on the Balance Sheet. Any recoveries from claims made on these policies related to this issue will be recorded as reductions in this line item, which will reduce our DD&A rate and replenish our cash expenditures.

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 $100.0 million and $140.0 million, respectively, and the policies are effective until June 1, 2013. We carry an additional $100.0 million of well control coverage effective until June 1, 2013 on certain wells at our Mahogany, Matterhorn, Virgo, Main Pass 107/108, Tahoe and SE Tahoe fields. A retention amount of $5.0 million for well control events and $40.5 million per hurricane occurrence must be satisfied by us before we are indemnified for losses. Pollution causing a negative environmental impact is characterized as a covered component of each of the well control and hurricane sections of the policy.

 

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We estimate that as of December 31, 2012, approximately 91% of the estimated future net revenues discounted at 10% (PV-10) attributable to our Gulf of Mexico properties are on platforms that are covered under our current insurance policies for named windstorm damage. This PV-10 percentage coverage is less than the previous year due to the acquisition of the Newfield Properties. Since we closed on the Newfield Properties near the end of named windstorm season and much of the property value is in subsea wells, we elected not to purchase named windstorm insurance on the assets at the time of the acquisition. There are certain other properties we have deemed as non-core and do not cover for named windstorm damage.

Our general and excess liability policy was recently renewed for another year and is effective until May 1, 2014. This policy provides for $300.0 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 requirement under the Ocean Pollution Act, we are required to evidence $150.0 million of financial responsibility to the Bureau of Safety and Environmental Enforcement. We qualify to self-insure for $54.0 million of this amount and the remaining $96.0 million is covered by insurance.

We are currently in the process of renewing our policies for well control and damages from named windstorms that expire on June 1, 2013 and believe we will be able to renew such policies at acceptable terms and premiums. 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 there could be an 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 claims, the insurers will not pay our claims. However, we are not 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, NGLs and natural gas, acquisition opportunities, and the results of our exploration and development activities. The following table presents our capital expenditures for exploration, development and other leasehold costs and acquisitions:

 

     Three Months Ended March 31,  
     2013      2012  
     (in thousands)  

Exploration (1)

   $ 60,624       $ 17,285   

Development (1)

     73,722         62,535   

Seismic, capitalized interest, other leasehold costs

     2,280         4,806   
  

 

 

    

 

 

 

Acquisitions and investments in oil and gas property/equipment

   $ 136,626       $ 84,626   
  

 

 

    

 

 

 

 

(1) Reported geographically in the subsequent table.

The following table presents our exploration and development capital expenditures geographically:

 

     Three Months Ended March 31,  
     2013      2012  
     (in thousands)  

Conventional shelf

   $ 42,220       $ 22,762   

Deepwater

     21,086         10,417   

Deep shelf

     21,237         237   

Onshore

     49,803         46,404   
  

 

 

    

 

 

 

Exploration and development capital expenditures

   $ 134,346       $ 79,820   
  

 

 

    

 

 

 

Our first quarter 2013 and 2012 capital expenditures were financed by cash flow from operating activities and cash on hand.

 

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The following table presents our wells drilled based on a completed basis:

 

     Three Months Ended March 31,  
     2013      2012  
     Gross      Net      Gross      Net  

Development wells:

           

Offshore wells:

           

Productive

     1         1.0         —           —     

Non-productive

     —           —           —           —     

Onshore wells:

           

Productive

     11         11.0         9         9.0   

Non-productive

     —           —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total development wells

     12         12.0         9         9.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Exploration wells:

           

Offshore wells:

           

Productive

     —           —           —           —     

Non Productive

     1         1.0         —           —     

Onshore wells:

           

Productive

     3         2.9         9         8.1   

Non-productive

     —           —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total exploration wells

     4         3.9         9         8.1   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total wells

     16         15.9         18         17.1   
  

 

 

    

 

 

    

 

 

    

 

 

 

We intend to continue to pursue acquisitions and joint venture opportunities during 2013 should we identify attractive opportunities. We are actively evaluating opportunities and expect to complement our drilling and development projects with acquisitions providing acceptable rates of return. We anticipate funding our 2013 capital budget and acquisitions with internally generated cash flow, cash on hand, borrowings under our revolving loan facility, and accessing the capital markets to the extent necessary.

Income taxes. During the three months ended March 31, 2013, we made no income tax payments and received no refunds. During the three months ended March 31, 2012, we made income tax payments of $10.2 million and received refunds of $0.4 million. For the remainder of 2013, we expect a substantial amount of our income tax will be deferred and expect payments to be primarily related to alternative minimum tax. We received a tax refund of $4.9 million in April 2013 related to 2012 estimated payments and anticipate tax refunds in the third quarter of 2013 of approximately $42.9 million attributable to tax loss carrybacks to 2010 and 2011. After the 2012 net operating loss carryback, the amount of remaining net operating losses generated in 2012 available to offset future taxable income in 2013 and forward is $35.4 million. We also have $22.3 million of alternative minimum tax credit carryforwards available to be utilized in 2013 and forward.

Dividends. During the first quarter of 2013 and 2012, we paid regular cash dividends of $0.08 per common share each quarter. On May 7, 2013, our board of directors declared a cash dividend of $0.09 per common share, payable on June 4, 2013 to shareholders of record on May 24, 2013.

Contractual obligations. Updated information on certain contractual obligations is provided in Financial Statements –Note 4 – Asset Retirement Obligations and Financial Statements – Note 6 – Long-Term Debt under Part I, Item 1 of this Form 10-Q. As of March 31, 2013, drilling rig commitments were approximately $48.4 million compared to $36.5 million as of December 31, 2012. The current drilling rig commitments all expire within one year from March 31, 2013. Other contractual obligations as of March 31, 2013 did not change materially, except for scheduled utilization, from the disclosures in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2012.

 

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Critical Accounting Policies

Our significant accounting policies are summarized in Note 1 of Notes to Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2012. Also refer to the Notes to Condensed Consolidated Financial Statements under Part 1, Item 1 of this Form 10-Q.

Recent Accounting Pronouncements

In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities which applies to certain items in the statement of financial position (balance sheet), and was further clarified in January 2013 by ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which clarified the scope of ASU 2011-11 to derivative instruments, repurchase agreements and securities lending transactions. The effective date for the amendments is for annual periods beginning after January 1, 2013, and interim periods within those annual periods. ASU 2011-11 requires disclosures of the gross and net amounts for items eligible for offset in the balance sheet. Although our derivative financial instruments are subject to master netting agreements, we record our derivative financial instruments on a gross basis by contract; therefore, the ASUs did not significantly affect our disclosures. Other items of the ASUs were not applicable to us.

In February 2013, the FASB issued ASU 2013-04, Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, which requires an entity that is joint and severally liable to measure the obligation as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of one or more co-obligors. Required disclosures include a description of the nature of the arrangement, how the liability arose, the relationship with co-obligors and the terms and conditions of the arrangement. The effective date for the amendment is for annual periods beginning after December 15, 2013, and interim periods within those annual periods. The amendment is to be applied retrospectively to all prior periods presented. We are currently assessing the impact of ASU 2013-04 to determine the effects on the balance sheet and disclosures, if any.

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Information about market risks for the first quarter of 2013 did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2012. As such, the information contained herein should be read in conjunction with the related disclosures in our Annual Report on Form 10-K for the year ended December 31, 2012.

Commodity Price Risk. Our revenues, profitability and future rate of growth substantially depend upon market prices of oil, NGLs and natural gas, which fluctuate widely. Oil, NGLs and natural gas price declines and volatility could adversely affect our revenues, net cash provided by operating activities and profitability. We currently have open crude oil derivative contracts to manage a portion of our exposure to commodity price risk from sales of oil for the balance of 2013 and the year 2014. As of March 31, 2013, these derivative contracts had a notional quantity of 3.1 MMBbls. We do not designate our commodity derivatives as hedging instruments. While these contracts are intended to reduce the effects of volatile oil prices, they may also limit future income from favorable price movements. See Financial Statements – Note 5– Derivative Financial Instruments under Part I, Item 1 of this Form 10-Q for additional information.

Interest Rate Risk. As of March 31, 2013, we had $143.0 million outstanding on our revolving bank credit facility. The revolving bank credit facility has a variable interest rate, which is primarily impacted by the rates for the LIBOR and the margin, which ranges from 2.00% to 2.75% depending on the amount outstanding. We currently do not have any derivative instruments related to interest rates.

 

Item 4. Controls and Procedures

We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC and that any material information relating to us is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions

 

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regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by Exchange Act Rule 13a-15(b), we performed an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have each concluded that as of March 31, 2013 our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our controls and procedures are designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

During the quarter ended March 31, 2013, there was no change in our internal control over financial reporting that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

 

Item 1. Legal Proceedings

Cameron Parish Louisiana Claim. Since 2009, certain Cameron Parish landowners have filed suits in the 38th Judicial District Court, Cameron Parish, Louisiana against us and our Chief Executive Officer, Tracy W. Krohn, as well as several other defendants unrelated to us. In their lawsuits, plaintiffs alleged that property they own has been contaminated or otherwise damaged by the defendants’ oil and gas exploration and production activities and they are seeking compensatory and punitive damages. During 2012, we settled claims with certain landowners and paid $10.0 million. We assessed the remaining claims to be probable and have accrued $1.3 million in our contingent liabilities as of March 31, 2013 and December 31, 2012, of which one claim was settled in April 2013 for $0.5 million. However, we cannot state with certainty that our estimates of additional exposure are accurate concerning this matter.

Qui Tam Litigation. On September 21, 2012, we were served with a complaint in a qui tam action filed under the federal False Claims Act by an employee of one of our contractors. The lawsuit, United States ex rel. Comeaux v. W&T Offshore, Inc., et al.; CA No. 10-494, was filed in the United States District Court for the Eastern District of Louisiana, against us and three other working interest owners related to claims associated with three of our operated production platforms. A qui tam action, also known as a “whistleblower” action, is a lawsuit brought by a private citizen seeking civil penalties or damages against a person or company on behalf of the government for alleged violations of law. If the claims are successful, the person filing the suit may recover a percentage of the damages or penalty from the lawsuit as a reward for exposing a wrongdoing and recovering funds on behalf of the government. The complaint was originally filed in 2010 but kept under confidential seal in order for the federal government to decide if it wished to intervene and take over the prosecution of the qui tam action. The government declined to intervene in this suit and the complaint was unsealed and made public in June 2012, thereby giving the plaintiff the opportunity to pursue the claims on behalf of the government.

The complaint alleges that environmental violations at three of our operated production platforms in the Gulf of Mexico violate the federal offshore lease provisions so that we, among other things, wrongfully retained benefits under the applicable leases. The alleged environmental violations include allegations of discharges of relatively small amounts of oil into the Gulf of Mexico, the failure to report and record such discharges, and falsification of certain produced water samples and related reports required under federal law. The events are alleged to have occurred in 2009. These are largely the same underlying environmental allegations that resulted in the plea agreement described in the audited financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2012. We have filed a motion to dismiss the plaintiff’s claims. The plaintiff dismissed his claims against the three other working interest owners after they filed motions to dismiss. The plaintiff conceded that certain of his claims should be dismissed in his reply to our motion to dismiss. The motion remains pending before the court.

We intend to vigorously defend the claims made in this lawsuit. While we have determined that the likelihood of an adverse outcome may be reasonably possible, the range of potential loss cannot yet be estimated, and accordingly, no accrual has been made.

 

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Insurance Claims. During the fourth quarter of 2012, underwriters of our excess liability policies (Indemnity Insurance Company of North America, New York Marine & General Insurance Company, Navigators Insurance Company, XL Specialty Insurance Company and Liberty Mutual Insurance Co.) filed declaratory judgment actions in the United States District Court for the Southern District of Texas seeking a determination that such policies do not cover removal of wreck and debris claims arising from Hurricane Ike that occurred in 2008. The court consolidated the various suits filed by the underwriters. We have not yet filed any claim under such excess policies, but we anticipate that such claims may reach $50.0 million in aggregate. In January 2013, we filed a motion for summary judgment seeking the court’s determination that such excess policies do in fact provide coverage for such removal of wreck and debris claims. The motion for summary judgment is pending. If the motion is successful, we expect to receive reimbursement for these costs once the claims are submitted. We have incurred $49.7 million to date in costs related to removal of wreck associated with platforms damaged by Hurricane Ike and expect to incur an additional $0.7 million. Removal of wreck costs are recorded in Oil and natural gas properties and equipment on the Balance Sheet. Any recoveries from claims made on these policies related to this issue will be recorded as reductions in this line item, which will reduce our DD&A rate and replenish our cash expenditures.

From time to time, we are party to other litigation or legal and administrative proceedings that we consider to be a part of the ordinary course of our business. Except for the matters noted above, we are not involved in any legal proceedings nor are we party to any pending or threatened claims that could, individually or in the aggregate, reasonably be expected to have a material adverse effect on our financial condition, cash flow or results of operations.

 

Item 1A. Risk Factors

Investors should carefully consider the risk factors included under Risk Factors under Part I, Item 1A in our Annual Report on Form 10-K for the year ended December 31, 2012, together with all of the other information included in this document, in our Annual Report on Form 10-K and in our other public filings, press releases and discussions with our management. Notwithstanding the matters discussed herein, there have been no material changes in our risk factors as previously disclosed in Part I, Item 1A in our Annual Report on Form 10-K for the year ended December 31, 2012.

 

Item 6. Exhibits

The exhibits to this report are listed in the Exhibit Index.

 

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on May 8, 2013.

 

W&T OFFSHORE, INC.
By:   /s/ JOHN D. GIBBONS
  John D. Gibbons
  Senior Vice President, Chief Financial Officer and Chief Accounting Officer, duly authorized to sign on behalf of the registrant

 

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EXHIBIT INDEX

 

Exhibit
Number

 

Description

    3.1   Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed February 24, 2006)
    3.2   Amended and Restated Bylaws of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.2 of the Company’s Registration Statement on Form S-1, filed May 3, 2004 (File No. 333-115103))
    3.3   Certificate of Amendment to the Amended and Restated Articles of Incorporation of W&T Offshore, Inc. (Incorporated by reference to Exhibit 3.3 of the Company’s Quarterly Report on Form 10-Q, filed July 31, 2012 (File No. 001-32414))
  31.1*   Section 302 Certification of Chief Executive Officer.
  31.2*   Section 302 Certification of Chief Financial Officer.
  32.1**   Section 906 Certification of Chief Executive Officer and Chief Financial Officer.
101.INS**   XBRL Instance Document.
101.SCH**   XBRL Schema Document
101.CAL**   XBRL Calculation Linkbase Document
101.DEF**   XBRL Definition Linkbase Document.
101.LAB**   XBRL Label Linkbase Document
101.PRE**   XBRL Presentation Linkbase Document.

 

* Filed herewith.
** Furnished herewith.

 

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