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Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

Form 10-Q

 

 

(MARK ONE)

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

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2012

 

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

FOR THE TRANSITION PERIOD FROM                    TO                     .

Commission File No. 333-172897

RAAM Global Energy Company

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   20-0412973

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

1537 Bull Lea Rd., Suite 200

Lexington, Kentucky

  40511
(Address of principal executive offices)   (Zip Code)

(859) 253-1300

(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 Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes  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. (Check one):

 

Large accelerated filer ¨

  

Accelerated filer ¨

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

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

As of May 9, 2012, there were 62,500 shares of common stock, no par value, outstanding.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

               Page  

Part I. Financial Information

  
   Item 1. Financial Statements   
     

Condensed Consolidated Balance Sheets

     5   
     

Condensed Consolidated Statements of Operations

     7   
     

Condensed Consolidated Statements of Comprehensive Income

     8   
     

Condensed Consolidated Statements of Cash Flows

     9   
     

Notes to Unaudited Condensed Consolidated Financial Statements

     10   
  

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

     19   
  

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     28   
  

Item 4. Controls and Procedures

     28   

Part II. Other Information

  
  

Item 1. Legal Proceedings

     29   
  

Item 1A. Risk Factors

     29   
  

Item 6. Exhibits

     29   

SIGNATURES

     30   

Exhibit Index

     31   

 

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CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

This report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements that relate to, among other things, our:

 

   

Forward-looking oil and natural gas reserve estimates;

 

   

future financial and operating performance and results;

 

   

business and financial strategy and budgets;

 

   

market prices;

 

   

drilling of wells and the anticipated results thereof;

 

   

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

 

   

competition and government regulations;

 

   

prospect development;

 

   

property acquisitions and sales; and

 

   

plans, forecasts, objectives, expectations and intentions.

All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward looking statements, although not all forward looking statements contain such identifying words. These forward looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

Forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from the anticipated future results or financial condition expressed or implied by the forward-looking statements. These risks, uncertainties and other factors include but are not limited to:

 

   

low and/or declining prices for oil and natural gas and oil and natural gas price volatility;

 

   

risks associated with drilling, including completion risks, cost overruns and the drilling of non-economic wells or dry holes;

 

   

ability to raise additional capital to fund future capital expenditures;

 

   

cash flow and liquidity;

 

   

ability to find, acquire, market, develop and produce new oil and natural gas properties;

 

   

uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures;

 

   

geological concentration of our reserves;

 

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discovery, acquisition, development and replacement of oil and natural gas reserves;

 

   

operating hazards attendant to the oil and natural gas business;

 

   

potential mechanical failure or under-performance of significant wells or pipeline mishaps;

 

   

delays in anticipated start-up dates;

 

   

actions or inactions of third-party operators of our properties;

 

   

ability to find and retain skilled personnel;

 

   

strength and financial resources of competitors;

 

   

federal and state regulatory developments and approvals;

 

   

environmental risks;

 

   

changes in interest rates;

 

   

weather conditions or events similar to those of September 11, 2001, Hurricanes Katrina, Rita, Gustav and Ike and the Deepwater Horizon explosion; and

 

   

worldwide political and economic conditions.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see Part II, “Item 1A. Risk Factors” and elsewhere in this report, the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2011, and the risk factors described in registration statements filed with the SEC.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data, and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing, and production activities may justify revisions of estimates that were made previously. If significant, such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

All subsequent written and oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section and any other cautionary statements that may accompany such forward looking statements. Except as otherwise required by applicable law, we disclaim any duty to update any forward looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this report.

 

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PART I. FINANCIAL INFORMATION

 

Item 1. Financial Statements

RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except for share amounts)

(unaudited)

 

     March 31,
2012
    December 31,
2011
 

Assets

    

Current assets:

    

Cash and cash equivalents

   $ 18,915      $ 51,743   

Accounts receivable, net of $1,005 provision for bad debts in 2012 and 2011

     4,667        5,642   

Revenues receivable

     28,112        31,532   

Income taxes receivable

     2,474        2,118   

Deferred tax asset

     2,094        —     

Commodity derivatives—current portion

     7,112        12,674   

Prepaid assets

     3,289        4,945   

Other current assets

     3,665        3,919   
  

 

 

   

 

 

 

Total current assets

     70,328        112,573   

Oil and gas properties (full-cost method):

    

Properties being amortized

     1,267,640        1,203,272   

Properties not subject to amortization

     109,774        111,621   

Less accumulated depreciation, depletion, and amortization

     (738,677     (720,062
  

 

 

   

 

 

 

Net oil and gas properties

     638,737        594,831   

Other assets:

    

Other capitalized assets, net

     7,092        7,183   

Commodity derivatives

     3,417        3,191   

Other

     5,187        5,698   
  

 

 

   

 

 

 

Total other assets

     15,696        16,072   
  

 

 

   

 

 

 

Total assets

   $ 724,761      $ 723,476   
  

 

 

   

 

 

 

See accompanying notes to the condensed consolidated financial statements.

 

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RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except for share amounts)

(unaudited)

 

$000,000,0 $000,000,0
     March 31,
2012
    December 31,
2011
 

Liabilities and shareholders’ equity

    

Current liabilities:

    

Accounts payable and accrued liabilities

   $ 42,181      $ 52,969   

Revenues payable

     24,820        29,319   

Interest payable—senior secured notes

     —          6,250   

Current taxes payable

     390        399   

Advances from joint interest partners

     227        1,019   

Commodity derivatives—current portion

     11,146        —     

Asset retirement obligations—current portion

     1,782        1,778   

Long-term debt—current portion

     130        1,929   

Deferred income taxes—current portion

     —          3,109   
  

 

 

   

 

 

 

Total current liabilities

     80,676        96,772   

Other liabilities:

    

Commodity derivatives

     8,396        4,244   

Asset retirement obligations

     25,638        25,010   

Long-term debt

     2,699        2,733   

Senior secured notes

     199,969        199,972   

Deferred income taxes

     114,039        105,095   

Other long-term liabilities

     499        467   
  

 

 

   

 

 

 

Total other liabilities

     351,240        337,521   
  

 

 

   

 

 

 

Total liabilities

     431,916        434,293   

Commitments and contingencies (see Note 10)

    

Shareholders’ equity and noncontrolling interest:

    

Common stock, no par value, 380,000 shares authorized, 62,500 outstanding in 2012 and 2011, respectively

     62,478        62,478   

Treasury stock at cost, 5,166 shares in 2012 and 2011

     (5,736     (5,736

Noncontrolling interest

     117        —     

Retained earnings

     227,114        224,513   

Accumulated other comprehensive income, net of taxes

     8,872        7,928   
  

 

 

   

 

 

 

Total shareholders’ equity and noncontrolling interest

     292,845        289,183   
  

 

 

   

 

 

 

Total liabilities and shareholders’ equity

   $ 724,761      $ 723,476   
  

 

 

   

 

 

 

See accompanying notes to the condensed consolidated financial statements.

 

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RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

(unaudited)

 

     Three Months Ended March 31  
     2012     2011  

Revenues:

    

Gas sales

   $ 23,023     $ 24,315  

Oil sales

     24,081        21,158   
  

 

 

   

 

 

 

Total revenues

     47,104        45,473   

Costs and expenses:

    

Production and delivery costs

     8,394        7,462   

Workover costs

     961        432   

Depreciation, depletion and amortization expenses

     18,965        17,139   

General and administrative expenses

     5,622        4,379   

Derivative expense (income)

     141        (247
  

 

 

   

 

 

 

Total operating expense

     34,083        29,165   
  

 

 

   

 

 

 

Income from operations

     13,021        16,308   

Other income (expenses):

    

Interest expense, net

     (6,107     (3,399

Other, net

     192        194   
  

 

 

   

 

 

 

Total other income (expenses)

     (5,915     (3,205
  

 

 

   

 

 

 

Income before taxes

     7,106        13,103   

Income tax provision

     2,825        2,655   
  

 

 

   

 

 

 

Net income including noncontrolling interest

   $ 4,281     $ 10,448  
  

 

 

   

 

 

 

Net income attributable to noncontrolling interest (net of tax)

     117        454   
  

 

 

   

 

 

 

Net income attributable to RAAM Global

   $ 4,164     $ 9,994  
  

 

 

   

 

 

 

See accompanying notes to the condensed consolidated financial statements.

 

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RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

(unaudited)

 

     Three Months Ended March 31  
     2012      2011  

Net income attributable to RAAM Global

   $ 4,164      $ 9,994  

Changes in fair value of hedges, net of taxes of $(563) and $4,458 in 2012 and 2011, respectively

     944         (7,056
  

 

 

    

 

 

 

Comprehensive income

   $ 5,108      $ 2,938  
  

 

 

    

 

 

 

See accompanying notes to the condensed consolidated financial statements.

 

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RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(unaudited)

 

     Three Months Ended March 31  
     2012     2011  

Operating activities

    

Net income including noncontrolling interest

   $ 4,281     $ 10,448  

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

    

Depreciation, depletion and amortization expenses

     19,421        17,574   

Deferred income taxes

     3,741        (1,770

Changes in assets and liabilities:

    

Accounts and revenues receivable

     4,394        1,157   

Income tax receivables

     (356     —     

Prepaids and other current assets

     1,909        40   

Change in derivatives, net

     21,578        4,211   

Accounts payable and accrued liabilities

     (10,847     (4,359

Revenues payable

     (4,499     1,940   

Interest payable on Senior Notes

     (6,250     (5,048

Current taxes payable

     (8     (67

Other long-term liabilities

     31        —     
  

 

 

   

 

 

 

Net cash provided by operating activities

     33,395        24,126   

Investing activities

    

Change in advances from joint interest partners

     (792     2,443   

Additions to oil and gas properties and equipment

     (62,034     (25,117

Proceeds from net sales of oil and gas properties

     —          13,384   
  

 

 

   

 

 

 

Net cash used in investing activities

     (62,826     (9,290

Financing activities

    

Payments on long-term borrowings

     (1,832     (1,031

Payment of dividends

     (1,563     (1,500

Other

     (2     48   
  

 

 

   

 

 

 

Net cash used in financing activities

     (3,397     (2,483
  

 

 

   

 

 

 

(Decrease) increase in cash and cash equivalents

     (32,828     12,353   

Cash and cash equivalents, beginning of period

     51,743        81,032   
  

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 18,915     $ 93,385  
  

 

 

   

 

 

 

See accompanying notes to the condensed consolidated financial statements.

 

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RAAM GLOBAL ENERGY COMPANY

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Nature of Business

RAAM Global Energy Company (“RAAM Global” or the “Company”) is a privately held company engaged primarily in the exploration and development of oil and gas properties and in the resulting production and sale of natural gas, condensate and crude oil. The Company’s production facilities are located in the Gulf of Mexico, offshore Louisiana and onshore Mississippi, Louisiana, Texas, and Oklahoma.

2. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements of RAAM Global include the accounts of RAAM Global, its wholly-owned subsidiaries, and variable interest entities where RAAM Global is the primary beneficiary (accounted for as noncontrolling interest). Intercompany accounts and transactions have been eliminated in consolidation. The accompanying interim Condensed Consolidated Financial Statements are unaudited; however, in the opinion of the Company’s management, all adjustments necessary for a fair statement of the Company’s interim financial results have been included. These adjustments were of a normal recurring nature. The results for the interim periods are not necessarily indicative of results to be expected for any other interim period or for the entire year.

The Condensed Consolidated Balance Sheet as of December 31, 2011, was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”). Certain notes and other information have been condensed or omitted from the interim financial statements presented in this quarterly report. Therefore, these financial statements and notes should be read in conjunction with the Company’s audited annual consolidated financial statements for the year ended December 31, 2011.

Use of Estimates

The preparation of financial statements in conformity with U.S. 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 period. Actual results may differ from those estimates. The Company’s most significant financial estimates are based on remaining proved oil and gas reserves.

Oil and Gas Properties

The Company uses the full-cost method of accounting for exploration and development costs. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves, including interest related to significant properties being evaluated and directly related overhead costs, are capitalized. Capitalized overhead costs amounted to $1.1 million and $1.4 million for the three months ended March 31, 2012 and 2011, respectively. The Company capitalized interest of $0.6 million and $1.8 million during the three months ended March 31, 2012 and 2011, respectively, related to significant properties not subject to amortization.

All capitalized costs of oil and gas properties are amortized through depreciation, depletion and amortization (“DD&A”) using the future gross revenue method whereby the annual provision is computed by dividing revenue earned during the period by future gross revenues at the beginning of the period, and applying the resulting rate to the cost of oil and gas properties, including estimated future development and abandonment costs.

Investments in unproved properties and major development projects are not amortized until proved reserves are attributed to the projects or until impairment occurs. If the results of an assessment indicate that the properties are impaired, that portion of such costs is added to the capitalized costs to be amortized.

 

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Unevaluated properties and associated costs not currently being amortized and included in oil and gas properties were $109.8 million and $111.6 million at March 31, 2012 and December 31, 2011, respectively. The Company believes that the unevaluated properties at March 31, 2012 will be substantially evaluated during 2012, 2013 and 2014, and the costs will begin to be amortized at that time.

Capitalized oil and gas property costs are subject to a “ceiling test,” which limits such costs to the aggregate of the estimated present value, discounted at 10%, of future net cash flows from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair value of unproved properties, each after income tax effects.

At March 31, 2012, the Company’s ceiling test computation did not result in a write-down and was based on twelve-month average prices of $94.23 per barrel of oil and $3.54 per MMBtu of natural gas. At December 31, 2011, the Company’s ceiling test computation did not result in a write-down and was based on twelve-month average prices of $92.71 per barrel of oil and $4.12 per MMBtu of natural gas.

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in current income.

During the second quarter of 2011, the Company sold approximately 16,000 acres onshore Mississippi to an unrelated third party oil and gas company. The sales price was $2.2 million and was recorded in cash and as an accumulated reduction to our net oil and gas properties on the accompanying condensed consolidated balance sheet. Under the full cost accounting method, the transaction was recorded as a reduction to net oil and gas properties with no income statement impact because the original cost of the acreage was not a significant percentage of the Company’s consolidated capitalized costs.

There are certain related party entities that are joint interest and revenue partners in certain of the Company’s properties. See Note 9 for further information.

Hedging Activities

The Company’s revenues are primarily the result of sales of its oil and natural gas production. Market prices of oil and natural gas may fluctuate and affect operating results. The Company engages in hedging activities that primarily include the use of floors, costless collars and futures transactions in order to minimize the downside risk from adverse price movements but allow for the realization of upside profits, if available. Costs and any benefits derived from the effective hedge portions of these activities are reflected in revenues from oil and gas production.

The Company follows the provisions of the Financial Accounting Standards Board (“FASB”) guidance related to accounting for derivative instruments and hedging activities. This guidance requires all derivatives to be reported as assets or liabilities at their fair values, and the balance sheet caption Commodity Derivatives is being used in the accompanying condensed consolidated balance sheets for this purpose. This guidance also imposes additional documentation requirements in order for derivatives to be accounted for as hedges of future risks. The Company designated all new commodity derivative swap instruments entered into in 2012 and 2011 as hedges for accounting purposes, so the related unrealized changes in their fair values are reported net of tax in the accompanying condensed consolidated balance sheet as a component of other comprehensive income. Any hedge ineffectiveness (which represents the amount by which the change in fair value of the derivative exceeds the change in cash flows of the forecasted transaction) is recorded in current-period earnings in the accompanying condensed consolidated statement of operations in Derivative expense (income). The Company did not designate all new option contracts (puts and calls) entered into in 2012 and 2011 as hedges for accounting purposes, so the related unrealized changes in their fair values are recorded in current-period earnings in the accompanying condensed consolidated statement of operations in Derivative expense (income). Actual monthly settlements is recorded as hedging (losses) gains in Gas sales and Oil sales in the accompanying condensed consolidated statement of operations. During the three months ended March 31, 2012 and 2011, the amounts of other comprehensive income related to hedge transactions that settled and were recorded in the accompanying condensed consolidated statements of operations were income of $5.1 million and $5.8 million, respectively, net of tax effects. The Company anticipates the amount of other comprehensive loss related to hedge transactions that will settle during the next twelve months will be $2.6 million, net of tax effects.

 

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Accounting for Asset Retirement Obligations

In accordance with the provisions of FASB guidance related to accounting for asset retirement obligations and FASB guidance on accounting for conditional asset retirement obligations, costs associated with the retirement of fixed assets (e.g., oil and gas production facilities, etc.) that the Company is legally obligated to incur are accrued. The fair value of the obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the fixed asset and are depreciated over the life of the applicable asset. The asset retirement cost recorded in Oil and gas properties being amortized at March 31, 2012 and December 31, 2011 was $6.5 million and $6.4 million, net of depreciation of $15.4 million and $15.1 million, respectively. Accretion of the discounted asset retirement obligations is recognized as an increase in the carrying amount of the liability and as an expense in Depreciation, depletion and amortization expenses on the accompanying condensed consolidated statement of operations.

The change in the Company’s asset retirement obligations (ARO) is set forth below:

 

In thousands       

Balance of ARO as of January 1, 2012

   $ 26,788  

Accretion expense

     191   

Additions

     441   

Settlement of ARO

     —     

Changes in ARO estimate

     —     
  

 

 

 

Balance of ARO as of March 31, 2012

   $ 27,420  
  

 

 

 

Operating Segments

The Company operates in one business segment – the exploration, development and sale of oil and gas.

New Accounting Pronouncements

In May 2011, the FASB issued Accounting Standards Update (“ASU”) Number 2011-04, amending Topic 820 – Fair Value Measurement, which the Company adopted on January 1, 2012. ASU Number 2011-04 changes certain fair value measurement principles and clarifies the application of existing fair value measurement guidance. Amendments include limiting the concepts of valuation premise and highest and best use to the measurement of nonfinancial assets. ASU Number 2011-04 also requires additional fair value disclosures including a qualitative discussion about the sensitivity of recurring Level 3 fair value measurements and the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed. This guidance did not have a significant impact on the Company’s financial statements.

In June 2011, the FASB issued ASU Number 2011-05, amending Topic 220 – Comprehensive Income, which the Company adopted on January 1, 2012. The ASU modifies alternative presentation standards, eliminating the option for disclosure of the elements of other comprehensive income within the statement of stockholder’s equity. Adoption of this ASU by the Company changed our existing presentation, but did not impact the components of other comprehensive income and accordingly did not have a material impact on the Company’s consolidated financial statements. In December 2011, the FASB issued ASU Number 2011-12, which defers the effective date of amendments to the presentation of reclassifications of items out of accumulated other comprehensive income in ASU Number 2011-05. This ASU supersedes certain pending paragraphs in ASU Number 2011-05.

3. Fair Value Measurements

FASB guidance establishes a three-level hierarchy for fair value measurements. The hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date.

 

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Level 1 – Valuation is based upon unadjusted quoted prices for identical assets or liabilities in active markets.

 

   

Level 2 – Valuation is based upon quoted prices for similar assets and liabilities in active markets, or other inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

 

   

Level 3 – Valuation is based upon other unobservable inputs that are significant to the fair value measurements.

The classification of fair value measurements within the hierarchy is based upon the lowest level of input that is significant to the measurement. At March 31, 2012 and December 31, 2011, the Company’s commodity derivative contracts were recorded at fair value. The fair values of these instruments were measured using valuations based upon quoted prices for similar assets and liabilities in active markets valued by reference to similar financial instruments, adjusted for credit risk and restrictions and other terms specific to the contracts (Level 2).

 

$xxxxx.xx $xxxxx.xx
     Fair Value Measurements Using Significant Other
Observable Inputs (Level 2)
 
Description    March 31, 2012     December 31, 2011  
In thousands             

Assets:

    

Fair value of commodity derivatives—current assets

   $ 7,112     $ 12,674  

Fair value of commodity derivatives—long-term assets

     3,417        3,191   
  

 

 

   

 

 

 

Total Assets

   $ 10,529     $ 15,865  
  

 

 

   

 

 

 

Liabilities:

    

Fair value of commodity derivatives—current liabilities

   $ (11,146   $ —     

Fair value of commodity derivatives—long-term liabilities

     (8,396     (4,244
  

 

 

   

 

 

 

Total Liabilities

   $ (19,542   $ (4,244
  

 

 

   

 

 

 

2015 Senior Secured Notes

During September 2010 and July 2011, the Company issued Senior Secured Notes. At March 31, 2012, the fair value of the Notes was estimated to be $208.8 million, based on the prices the bonds have recently been quoted at in the market, which represent Level 2 inputs. As of March 31, 2012, a total of $200.0 million notional amount of the Notes was outstanding. The carrying amount of the Notes was $200.0 million as of March 31, 2012.

4. Accounts and Revenues Receivable

Accounts and revenues receivable at March 31, 2012 and December 31, 2011 were $32.8 million and $37.2 million, respectively, all of which were due from companies in the oil and gas industry. Of the revenues receivable, $24.0 million and $27.0 million were due from five companies at March 31, 2012 and December 31, 2011, respectively.

Since all of RAAM Global’s accounts receivable from purchasers and joint interest owners at March 31, 2012 and December 31, 2011 resulted from sales of crude oil, condensate, natural gas and/or joint interest billings to third-party companies in the oil and gas industry, this concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. Management believes that allowances for doubtful accounts were adequate to absorb estimated losses as of March 31, 2012 and December 31, 2011. Management obtains letters of credit from its major purchasers and continually evaluates the creditworthiness of its partners.

 

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5. Commodity Derivative Instruments and Hedging Activities

In order to manage the variability in cash flows associated with the sale of its oil and gas production, the Company has developed a strategy to combine the use of floors, costless collars and futures transactions in order to minimize the downside risk from adverse price movements but allow for the realization of upside profits, if available. The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of those contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty.

With respect to any collar transaction, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction, and the Company is required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price of such transaction. For any particular floor contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction. The Company is not required to make any payment in connection with the settlement of a floor contract. Monthly settlements of these contracts are reflected in revenue from oil and gas production.

All of the Company’s commodity derivative transactions are settled based on reported settlement prices on the New York Mercantile Exchange (“NYMEX”). The estimated fair value of these transactions is based on various factors that include closing exchange prices on the NYMEX, over-the-counter quotations, volatility and the time value of options. The calculation of the fair value of collars and floors utilizes the Black-Scholes option-pricing model. Since the swap transactions were designated as hedges, the Company records the changes in fair value of these transactions as Accumulated Other Comprehensive Income in the accompanying condensed consolidated balance sheets with the ineffective portion of the change in fair value reported as Derivative expense (income) in the accompanying condensed consolidated statements of operations. See Note 2, Basis of Presentation and Significant Accounting Policies, for additional information on the Company’s hedging activities.

For the three months ended March 31, 2012 and 2011, the Company realized a net increase in oil and gas revenues related to hedging transactions of approximately $5.1 million and $5.8 million, respectively. The increase in oil and gas revenues related to hedging transactions for the three months ended March 31, 2012 includes the monetization of gas hedges in February 2012 resulting in additional revenues of $1.3 million for forecasted transactions that would have settled during the quarter. The remaining $22 million of monetized hedges were recorded in accumulated other comprehensive income, net of tax effects and will be recognized in revenues in the period when the contract would have settled if the hedges had not been monetized. Hedge ineffectiveness for the derivative swap instruments was $1.9 million for the three months ended March 31, 2012. The options had an unrealized change in fair value during the quarter ended March 31, 2012 of $(2.0) million. Hedge ineffectiveness was $0.2 million for the three months ended March 31, 2011.

 

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As of March 31, 2012, the Company held the commodity derivative instruments shown below related to the forecasted sale of its U.S. Gulf Coast natural gas production for 2012, 2013, 2014 and 2015:

 

Remaining Contract Term

  

Contract
Type

   Volume in
MMBtus/
Month
     NYMEX
Strike
Price
 

April 2012—December 2012

   Swap      61,111       $ 3.05  

April 2012—December 2012

   Swap      61,111       $ 3.05  

April 2012—December 2012

   Swap      376,556       $ 3.00  

April 2012—December 2012

   Swap      152,778       $ 3.67  

April 2012—December 2012

   Swap      220,444       $ 3.00  

April 2012—December 2012

   Swap      309,233       $ 2.94  

January 2013—September 2013

   Swap      90,556       $ 3.70  

January 2013—December 2013

   Swap      152,083       $ 3.67  

January 2013—December 2013

   Swap      152,083       $ 3.81  

January 2013—December 2013

   Swap      150,542       $ 3.81  

January 2013—December 2013

   Swap      122,325       $ 3.79  

January 2014—June 2014

   Swap      150,833       $ 4.09  

January 2014—December 2014

   Swap      152,083       $ 3.67  

January 2014—December 2014

   Swap      158,833       $ 4.15  

January 2014—December 2014

   Swap      79,850       $ 4.00  

July 2014—December 2014

   Swap      30,667       $ 4.00  

January 2015—December 2015

   Swap      167,042       $ 4.94  

January 2015—December 2015

   Swap      85,433       $ 4.35  

 

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As of March 31, 2012, the Company held the commodity derivative instruments shown below related to the forecasted sale of its U.S. Gulf Coast oil production for 2012, 2013 and 2014:

 

Remaining Contract Term

  

Contract
Type

   Volume in
BBls/
Month
     NYMEX
Strike
Price
 

April 2012—September 2012

   Swap      24,400       $ 82.25  

April 2012—December 2012

   Call      3,667       $ 110.00  

April 2012—December 2012

   Swap      17,478       $ 100.02  

April 2012—December 2012

   Swap      17,433       $ 100.30  

April 2012—December 2012

   Put      59,583       $ 75.00  

April 2012—June 2012

   Swap      6,000       $ 88.52  

April 2012—June 2012

   Swap      6,000       $ 87.05  

April 2012—June 2012

   Swap      5,000       $ 87.50  

July 2012—September 2012

   Swap      12,000       $ 88.76  

July 2012—September 2012

   Swap      5,000       $ 87.80  

October 2012—December 2012

   Swap      39,867       $ 84.00  

January 2013—June 2013

   Swap      21,117       $ 84.70  

January 2013—December 2013

   Call      13,292       $ 125.00  

January 2013—December 2013

   Swap      8,833       $ 95.72  

January 2013—December 2013

   Put      21,292       $ 70.00  

July 2013—December 2013

   Swap      15,333       $ 85.50  

January 2014—June 2014

   Swap      24,133       $ 85.40  

July 2014—September 2014

   Swap      21,467       $ 85.90  

Additional information regarding the fair value of the Company’s derivatives can be referenced in Note 3, Fair Value Measurements.

6. Debt

2015 Senior Secured Notes

On September 24, 2010, we completed an offering of $150.0 million senior secured notes at a coupon rate of 12.5% (the “Original Notes”) with a maturity date of October 1, 2015. Interest on the Original Notes is payable in cash semi-annually in arrears on April 1 and October 1 of each year, which commenced on April 1, 2011, to holders of record at the close of business on the preceding March 15 or September 15. Interest on the Original Notes is computed on the basis of a 360-day year of twelve 30-day months. The Original Notes were sold at 99.086% of their face amount and were recorded at their discounted amount, with the discount to be amortized over the life of the notes. The Company used a portion of the net proceeds from the offering to repay all outstanding indebtedness under the revolving credit facility and the remainder of the proceeds was used to fund a portion of our planned capital expenditures for development and drilling. On May 10, 2011, the Company closed an exchange offer registering substantially all of the Original Notes.

On July 15, 2011, the Company completed the issuance and sale of $50.0 million aggregate principal amount of additional 12.5% Senior Notes due 2015 (the “Additional Notes,” collectively with the Original Notes, the “Notes”). The Additional Notes are additional notes permitted under the indenture dated as of September 24, 2010, pursuant to which the Company initially issued the Original Notes, as supplemented by the First Supplemental Indenture dated as of July 15, 2011. The Additional Notes were sold at 102.5% of their face amount and were recorded at their

 

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premium amount, with the premium to be amortized over the life of the notes. The Additional Notes have identical terms, other than the issue date and issue price, and constitute part of the same series as the initially issued notes. On November 18, 2011, the Company closed an exchange offer registering all of the Additional Notes.

As of March 31, 2012, a total of $200.0 million notional amount of the Notes were outstanding. The carrying amount of the Notes was $200.0 million as of March 31, 2012. At March 31, 2012, the fair value of the Notes was estimated to be $208.8 million, based on the prices the Notes have recently been quoted at in the market.

The Notes are guaranteed on a senior secured basis by each of our existing and future domestic subsidiaries that guarantee indebtedness under our amended revolving credit facility. The Notes and the guarantees are secured by a security interest in substantially all of our and our existing future domestic subsidiaries’ (other than certain future unrestricted subsidiaries’) assets to the extent they constitute collateral under our Amended Revolving Credit Facility, subject to certain exceptions. Pursuant to an Intercreditor Agreement, the lien securing the Notes is subordinated and junior to liens securing our Amended Revolving Credit Facility.

Amended Revolving Credit Facility

On November 29, 2011, the Company’s revolving credit facility was amended (the “Amended Revolving Credit Facility”). The borrowing base remains $62.5 million which was undrawn at March 31, 2012. The Credit Agreement governing the amended revolving credit facility includes covenants restricting certain of the Company’s financial ratios, including its current ratio and a debt coverage ratio, and a limitation on general and administrative expenses. The covenants also include limitations on borrowings, investments, and distributions. The Company is in compliance with these debt covenants at March 31, 2012.

Promissory Note

The Company has a promissory note with GE Commercial Finance Business Property Corporation (“GECF”) with a balance of $2.8 million at March 31, 2012 related to the construction of the Houston office building. The GECF note requires monthly installments of principal and interest in the amount of $27,000 until September 1, 2025. There are no covenant requirements under this promissory note.

Finance Agreement

During May 2011, the Company entered into an agreement to finance the premiums for its annual insurance policies with Imperial Credit Corporation. The finance agreement required monthly installments of principal and interest in the amount of $0.9 million until February 1, 2012. This obligation was extinguished in February 2012. There were no covenant requirements under this agreement.

7. Income Taxes

The Income tax provision for the three months ended March 31, 2012 was $2.8 million or an effective tax rate of 39.8%, compared to $2.7 million or an effective tax rate of 20.3% for the three months ended March 31, 2011. The Company’s effective income tax rate for the three months ended March 31, 2012 and 2011 differed from the federal statutory rate of 35.0% primarily because of state and local income taxes, percentage of depletion in excess of basis, the domestic production activities deduction and certain other permanent differences.

8. Shareholders’ Equity

During 2012, dividends were paid at $25.00 per share to shareholders of record effective March 15, 2012. During 2011, dividends were paid at $25.00 per share to shareholders of record effective March 1, 2011.

 

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9. Related-Party Transactions

There are certain related party entities that are joint interest and revenue partners in certain of the Company’s properties. Amounts due from such related parties of approximately $0.9 million and $1.3 at March 31, 2012 and December 31, 2011, respectively, are included in Accounts receivable in the Company’s condensed consolidated balance sheets and represent joint interest owner receivables. Amounts due to such related parties of $5.8 million and $6.8 million at March 31, 2012 and December 31, 2011, respectively, are included in Revenues payable in the Company’s condensed consolidated balance sheets and represent revenue owner payables.

10. Commitments and Contingencies

The Company has been named as a defendant in certain lawsuits arising in the ordinary course of business. While the outcome of the lawsuits cannot be predicted with certainty, management does not expect that any of these matters will have a material adverse effect on the financial position, cash flows or results of operations of the Company.

11. Subsidiary Guarantors of Parent Company Debt

During 2010 and 2011, RAAM Global issued the Notes, described in Note 6, Debt. Each of RAAM Global’s wholly owned subsidiaries are guarantors of the Notes. The parent company has no independent assets or operations, as defined in SEC regulation S-X, the guarantees are joint and several, and are subject to certain customary automatic subsidiary release provisions.

 

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

The following discussion and analysis should be read in conjunction with our historical consolidated financial statements and the notes to the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2011. Our operating results for the periods discussed may not be indicative of future performance. The following discussion and analysis includes forward-looking statements and should be read in conjunction with “Risk Factors” under Part II, Item 1A of this report, along with “Cautionary Statement Regarding Forward-Looking Statements” at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are a privately held oil and natural gas exploration and production company engaged in the exploration, development, production and acquisition of oil and gas properties. Our operations are located in the Gulf of Mexico, offshore Louisiana and onshore Louisiana, Texas, Oklahoma, California and New Mexico. We focus on the development of both conventional oil and gas plays and unconventional resource plays. Historically, we have successfully developed conventional oil and gas plays in the offshore Gulf of Mexico and onshore Texas and Louisiana. More recently, we have redirected our focus to the acquisition and development of acreage in the shallow oil, tight gas sand and oil shale plays throughout the United States. Since 2007, we have targeted unconventional plays, including tight gas and oil in shale in Oklahoma, California, and New Mexico and have obtained land positions in these plays.

Our assets create a portfolio of production, resources and opportunities that are balanced between long-lived, dependable production and exploration and development opportunities. Current development projects are focused on three main areas: shallow waters offshore, onshore conventional assets in Texas, Louisiana and Oklahoma, and unconventional assets in Oklahoma and California. We have selectively acquired and accumulated a portfolio of oil and gas leases in both oil and gas prone unconventional areas domestically. We plan to continue to augment our Gulf Coast production, increase our proved reserves and the reserve life of our portfolio through the development of these unconventional assets.

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

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

The primary factors affecting our production levels are capital availability, the success of our drilling program and our inventory of drilling prospects. In addition, we face the challenge of natural production declines. As initial reservoir pressures are depleted, production from a given well decreases. We attempt to overcome this natural decline primarily through drilling our existing undeveloped reserves. Our future growth will depend on our ability to continue to add reserves in excess of production. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenues and, as a result, cash flow from operations.

 

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We focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long–term operations. Our future cash flows from operations are dependent upon our ability to manage our overall cost structure.

Recent Developments

Our first well in California was successfully drilled and completed. It was brought online in mid-April. Initial flow rates, as of May 4, 2012, were approximately 400 barrels of oil per day net, with no water production.

How We Evaluate Our Operations

We use a variety of financial and operational measures to assess our performance. Among these measures are (1) volumes of crude oil and natural gas produced, (2) crude oil and natural gas prices realized, (3) per unit operating and administrative costs and (4) EBITDA (as defined below). The following table contains financial and operational data for the three months ended March 31, 2012 and 2011.

 

     Three Months Ended March 31  
     2012      2011  

Average daily production:

     

Oil (Bbl per day)

     2,804         2,520   

Natural gas (Mcf per day)

     51,658         42,995   

Oil equivalents (Boe per day)

     11,414         9,686   

Average prices: (1)

     

Oil ($/Bbl)

   $ 94.37       $ 93.27   

Natural gas ($/Mcf)

   $ 4.90       $ 6.28   

Oil equivalents ($/Boe)

   $ 45.35       $ 52.16   

Production expense ($/Boe)

   $ 8.08       $ 8.56   

General and administrative expense ($/Boe)

   $ 5.41       $ 5.02   

Net income (in thousands)

   $ 4,164       $ 9,994   

EBITDA (2) (in thousands)

   $ 32,076       $ 33,224   

 

(1) 

Average prices presented give effect to our hedging activities and the monetization of gas hedges during February 2012. Please see “Note 5, Commodity Derivative Instruments and Hedging Activities” for a discussion of our hedging activities.

(2) 

EBITDA as used herein represents net income before interest expense, income taxes, depreciation, depletion and amortization. We present EBITDA because some investors believe it is an important supplemental measure of our performance, frequently used in evaluating companies in our industry. EBITDA is not a measurement of our financial performance under accounting principles generally accepted in the United States (“U.S. GAAP”) and should not be considered as an alternative to net income, operating income or any other performance measure derived in accordance with U.S. GAAP or as an alternative to net cash provided by operating activities as a measure of our profitability or liquidity. EBITDA has significant limitations, including that it does not reflect our cash requirements for capital expenditures, contractual commitments, working capital or debt service. In addition, other companies may calculate EBITDA differently than we do, limiting their usefulness as comparative measures.

 

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The following table sets forth a reconciliation of net income as determined in accordance with U.S. GAAP to EBITDA for the periods ended March 31, 2012 and 2011.

 

     Three Months Ended March 31  
     2012      2011  
In thousands              

Net income

   $ 4,164       $ 9,994   

Interest expense

     6,122         3,436   

Depreciation, depletion and amortization

     18,965         17,139   

Income taxes

     2,825         2,655   
  

 

 

    

 

 

 

EBITDA

   $ 32,076       $ 33,224   
  

 

 

    

 

 

 

Results of Operations

The following table sets forth the unaudited results of operations for the three months ended March 31, 2012 and 2011 in thousands.

 

     Three Months Ended March 31  
     2012     2011  

Revenues:

    

Gas sales

   $ 23,023      $ 24,315   

Oil sales

     24,081        21,158   
  

 

 

   

 

 

 

Total revenues

     47,104        45,473   

Costs and expenses:

    

Production and delivery costs

     8,394        7,462   

Workover costs

     961        432   

Depreciation, depletion and amortization expenses

     18,965        17,139   

General and administrative expenses

     5,622        4,379   

Derivative expense (income)

     141        (247
  

 

 

   

 

 

 

Total operating expense

     34,083        29,165   
  

 

 

   

 

 

 

Income from operations

     13,021        16,308   

Other income (expenses):

    

Interest expense, net

     (6,107     (3,399

Other, net

     192        194   
  

 

 

   

 

 

 

Total other income (expenses)

     (5,915     (3,205
  

 

 

   

 

 

 

Income before taxes

     7,106        13,103   

Income tax provision

     2,825        2,655   
  

 

 

   

 

 

 

Net income including noncontrolling interest

   $ 4,281      $ 10,448   
  

 

 

   

 

 

 

Net income attributable to noncontrolling interest (net of tax)

     117        454   
  

 

 

   

 

 

 

Net income attributable to RAAM Global

   $ 4,164      $ 9,994   
  

 

 

   

 

 

 

 

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Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

Revenues

Oil and natural gas production. Oil and natural gas production for the three months ended March 31, 2012 increased to 1.1 MMBoe from 0.9 MMBoe for the three months ended March 31, 2011. During the three months ended March 31, 2012, production from new discoveries in the Yegua area onshore Texas and in the shallow waters of Louisiana were partially offset by normal production declines in the more mature fields of West Cameron in the federal waters.

Total revenues. Total revenues for the three months ended March 31, 2012 increased to $47.1 million from $45.5 million for the three months ended March 31, 2011. The increase in revenue was mainly attributable to the monetization of gas hedges resulting in additional revenues of $1.3 million for forecasted transactions that would have settled during the quarter. Gross revenues net of the $1.3 million in hedges resulted in flat revenues due to increased gas and oil production coupled with lower gas prices and approximately the same oil prices. The average sales price for the three months ended March 31, 2012 was $45.35 per Boe as compared to $52.16 per Boe for the three months ended March 31, 2011.

Operating costs and expenses

Production and delivery costs. Production and delivery costs were $8.4 million, or $8.08 per Boe, for the three months ended March 31, 2012, and $7.5 million, or $8.56 per Boe, for the comparable period in 2011. The increase in production and delivery costs was primarily attributable to higher costs for boat transportation, contract pumping services and Safety and Environmental Management System (SEMS) compliance efforts during the 2012 period than those incurred during the 2011 period.

Workover costs. Our workover costs for the three months ended March 31, 2012 were $1.0 million, or $0.93 per Boe, and $0.4 million in the comparable period of 2011, or $0.50 per Boe. The increase in workover costs from the comparable period in 2011 was primarily a result of changes in projects needed to manage our wells and maintain efficient production levels.

Depreciation, depletion and amortization expenses. Depreciation, depletion and amortization expenses for the three months ended March 31, 2012 increased to $19.0 million from $17.1 million for the three months ended March 31, 2011. The increase in depreciation, depletion and amortization was primarily due to slightly higher future gross revenues on reserves and a larger net oil and gas property cost base at March 31, 2012.

General and administrative expenses. General and administrative expense increased to $5.6 million during the three months ended March 31, 2012, from $4.4 million in the comparable period in 2011. The increase in general and administrative expense was primarily due to higher travel and consultant costs for projects in California, Oklahoma and Texas.

Interest expense, net. Net interest expense increased to $6.1 million for the three months ended March 31, 2012, from $3.4 million for the three months ended March 31, 2011. Actual interest incurred during the first quarter of 2012 was $6.2 million offset by capitalized interest of $0.6 million. Actual interest incurred during the first quarter of 2011 was $4.8 million offset by capitalized interest of $1.8 million. Debt balances averaged $200.0 million during the three months ended March 31, 2012 and $150.0 million during the three months ended March 31, 2011. Interest rates averaged 12.5% during the three months ended March 31, 2012 and 2011.

Income tax provision. For the three months ended March 31, 2012, the Company recorded income tax expense of $2.8 million as compared to income tax expense of $2.7 million for the three months ended March 31, 2012. Income tax expense recognized was based on an effective tax rate calculation of approximately 39.8% at March 31, 2012 and approximately 20.3% at March 31, 2011. The difference in the rates for the first quarters of 2012 and 2011 was primarily due to a change in the expected annual financial results which affected both the federal and state annualized tax rates.

 

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Liquidity and Capital Resources

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

The Company spent approximately $62 million on capital expenditures during the first three months of 2012. We anticipate spending an additional $110 million on capital expenditures during the remainder of 2012. Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Capital Expenditure Budget

Our total 2012 capital expenditure budget is approximately $172 million, of which approximately $62 million was expended in the first three months of 2012. The remaining capital budget of $110 million consists of:

 

   

$26 million for geological and geophysical costs;

 

   

$3 million for onshore drilling and development prospects in Alabama;

 

   

$34 million for onshore drilling and development prospects in Texas;

 

   

$23 million for onshore drilling and development prospects in Oklahoma and California;

 

   

$17 million for final completion operations and platform and infrastructure upgrades for all project areas; and

 

   

$7 million for plugging and abandonment costs primarily for offshore properties.

While we have budgeted $110 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. To date, our 2012 capital budget has been funded from debt financing and our cash flows from operations. We believe cash flows from operations and borrowings under our Amended Revolving Credit Facility should be sufficient to fund the remainder of our 2012 capital expenditure budget.

As of March 31, 2012, we had no indebtedness outstanding under our revolving credit facility and $200 million in Notes outstanding.

We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see Part I, Item 3, “Quantitative and Qualitative Disclosures About Market Risk.”

We actively review acquisition opportunities on an ongoing basis. Our ability to make significant additional acquisitions would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.

 

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The table below discloses the net cash provided by (used in) operating activities, investing activities, and financing activities for the three months ended March 31, 2012 and 2011:

 

     Three Months Ended March 31  
     2012     2011  
In thousands             

Net cash provided by operating activities

   $ 33,395      $ 24,126   

Net cash used in investing activities

     (62,826     (9,290

Net cash used in financing activities

     (3,397     (2,483
  

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

   $ (32,828   $ 12,353   
  

 

 

   

 

 

 

Cash flows provided by operating activities

Operating activities provided cash totaling $33.4 million during the three months ended March 31, 2012 as compared to cash provided by operating activities of $24.1 million during the three months ended March 31, 2011. The increase in operating cash flows during the three months ended March 31, 2012 was principally attributable to higher accounts payable balances during the period offset by the payment of interest on our Notes during the period.

Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see Part I, Item 3, “Quantitative and Qualitative Disclosures About Market Risk” below.

Cash flows used in investing activities

Investing activities used cash totaling $62.8 million during the three months ended March 31, 2012 as compared to cash used in investing activities of $9.3 million during the comparable period in 2011. Cash used in investing activities during the three months ended March 31, 2012 increased as compared to the same period of 2011 primarily because of increased activity in Louisiana state waters and onshore Texas. An asset sale occurred during the first quarter of 2011 generating $13.4 million in proceeds; no such sale took place in the first quarter of 2012.

Our capital expenditures for drilling, development and acquisition costs for the three months ended March 31, 2012 and 2011 are summarized in the following table (in thousands):

 

     Three Months Ended March 31  
     2012      2011  

Project Area

     

Federal

   $ 727       $ 2,386   

Shallow State Waters

     33,959         4,551   

Onshore Texas, Louisiana and Mississippi

     21,306         14,014   

Oklahoma and Mid-Continent

     6,042         4,166   
  

 

 

    

 

 

 

Total

   $ 62,034       $ 25,117   
  

 

 

    

 

 

 

Cash flows provided by financing activities

Financing activities used cash totaling $3.4 million during the three months ended March 31, 2012 as compared to cash used by financing activities of $2.5 million during the comparable period in 2011. Cash flows used in financing activities during the first three months of 2012 consisted primarily of $1.8 million in payments on the Company’s insurance premium financing and payments of $1.5 million for shareholder dividends. Cash flows used in financing activities during the first three months of 2011 were mainly comprised of $1.0 million in payments on the Company’s insurance premium financing and payments of $1.5 million for shareholder dividends.

 

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Off-Balance Sheet Arrangements

As of March 31, 2012, the Company had no off-balance sheet arrangements or guarantees of third party obligations. The Company has no plans to enter into any off-balance sheet arrangements in the foreseeable future.

Oil and Gas Hedging

As part of our risk management program, we hedge a portion of our anticipated oil and gas production to reduce our exposure to fluctuations in oil and natural gas prices. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and more price sensitive drilling programs. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions.

While the use of these hedging arrangements limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements. In addition, the use of hedging transactions may involve basis risk. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. All of our hedging transactions are settled based upon reported settlement prices on the NYMEX.

At March 31, 2012, on a BOE basis, commodity derivative instruments were in place covering approximately 79% of our projected oil and natural gas sales through 2012, approximately 49% of our projected oil and natural gas sales for 2013, approximately 40% of our projected oil and natural gas sales for 2014 and approximately 18% of our projected oil and natural gas sales for 2015. Approximately 80% of the Company’s remaining 2012 gas production, approximately 61% of the Company’s 2013 gas production, approximately 64% of the Company’s 2014 gas production, approximately 47% of the Company’s 2015 gas production, approximately 75% of the Company’s remaining 2012 oil production, approximately 28% of the Company’s 2013 oil production, and approximately 15% of the Company’s 2014 oil production will yield minimum prices under the contracts as discussed in “Notes to Unaudited Condensed Consolidated Financial Statements–Note 5, Commodity Derivative Instruments and Hedging Activities.” Future oil and gas sales prices on other production will fluctuate according to market conditions.

As of March 31, 2012, the Company had entered into the following oil derivative instruments:

 

     NYMEX Contract Price  
     Total Futures      Total Options  
     Volume in Bbls/Mo      Weighted Average Fixed
Price
     Volume in Bbls/Mo      Weighted Average
Strike Price
 

Period

           

2012(1)

     56,850       $ 91.68         47,438       $ 77.03   

2013

     27,058       $ 88.52         34,584       $ 91.14   

2014(2)

     17,433       $ 85.55         —         $ —     

 

(1) 

Average hedged volume is calculated for the remainder of the 2012 year.

(2) 

The Company currently does not have any volumes hedged for futures in the fourth quarter of 2014. The calculation of average hedged volumes is for the full year of 2014.

 

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As of March 31, 2012, the Company had entered into the following natural gas derivative instruments:

 

     NYMEX Contract Price  
     Total Futures  
     Volume in
Mbtu/Mo
     Weighted Average
Fixed Price
 

Period

     

2012(1)

     1,181,233       $ 3.08   

2013

     644,950       $ 3.76   

2014

     481,517       $ 3.96   

2015

     252,475       $ 4.74   

 

(1) 

Average hedged volume is calculated for the remainder of the 2012 year.

The swap transactions were designated as cash flow hedges; the option contracts do not follow hedge accounting. Please see “Notes to Unaudited Condensed Consolidated Financial Statements–Note 2, Basis of Presentation and Significant Accounting Policies” included in Part I, Item 1 for additional discussion regarding the accounting applicable to our hedging program.

Senior Secured Notes

On September 24, 2010, we completed an offering of $150.0 million senior secured notes at a coupon rate of 12.5% (the “Original Notes”) with a maturity date of October 1, 2015. Interest on the Original Notes is payable in cash semi-annually in arrears on April 1 and October 1 of each year, which commenced on April 1, 2011, to holders of record at the close of business on the preceding March 15 or September 15. Interest on the Original Notes is computed on the basis of a 360-day year of twelve 30-day months. The Original Notes were sold at 99.086% of their face amount and were recorded at their discounted amount, with the discount to be amortized over the life of the notes. The Company used a portion of the net proceeds from the offering to repay all outstanding indebtedness under the revolving credit facility and the remainder of the proceeds was used to fund a portion of our planned capital expenditures for development and drilling. On May 10, 2011, the Company closed an exchange offer registering substantially all of the Original Notes.

On July 15, 2011, the Company completed the issuance and sale of $50.0 million aggregate principal amount of additional 12.5% Senior Notes due 2015 (the “Additional Notes,” collectively with the Original Notes, the “Notes”). The Additional Notes are additional notes permitted under the indenture dated as of September 24, 2010, pursuant to which the Company initially issued the Original Notes, as supplemented by the First Supplemental Indenture dated as of July 15, 2011. The Additional Notes were sold at 102.5% of their face amount and were recorded at their premium amount, with the premium to be amortized over the life of the notes. The Additional Notes have identical terms, other than the issue date and issue price, and constitute part of the same series as the Original Notes. On November 18, 2011, the Company closed an exchange offer registering all of the Additional Notes.

As of March 31, 2012, a total of $200.0 million notional amount of the Notes was outstanding. The carrying amount of the Notes was $200.0 million as of March 31, 2012.

The Notes are guaranteed on a senior secured basis by each of our existing and future domestic subsidiaries that guarantee indebtedness under our Amended Revolving Credit Facility. The Notes and the guarantees are secured by a security interest in substantially all of our and our existing future domestic subsidiaries’ (other than certain future unrestricted subsidiaries’) assets to the extent they constitute collateral under our Amended Revolving Credit Facility, subject to certain exceptions. Pursuant to an Intercreditor Agreement, the lien securing the Notes is subordinated and junior to liens securing our Amended Revolving Credit Facility.

 

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Amended Revolving Credit Facility

On November 29, 2011, the Company’s Revolving Credit Facility was amended. The borrowing base remains $62.5 million which was undrawn at March 31, 2012. The Credit Agreement governing the amended revolving credit facility includes covenants restricting certain of the Company’s financial ratios, including its current ratio and a debt coverage ratio, and a limitation on general and administrative expenses. The covenants also include limitations on borrowings, investments, and distributions. The Company is in compliance with these debt covenants at March 31, 2012. The maturity date is July 1, 2015.

Borrowings under our Amended Revolving Credit Facility are limited to a borrowing base calculated based on our proved reserves. Borrowings bear interest at a floating rate equal to either the prime rate of interest in effect from time to time (plus a certain percentage in certain circumstances) or LIBOR plus a certain percentage based on the amount of availability under our Amended Revolving Credit Facility. As of March 31, 2012, the Company had no borrowings outstanding under the credit facility.

Our obligations under the Amended Revolving Credit Facility are secured by a lien on substantially all of our and our subsidiaries’ current and fixed assets (subject to certain exceptions).

Critical Accounting Policies and Estimates

This Quarterly Report on Form 10-Q has been prepared pursuant to the rules and regulations of the SEC applicable to interim financial information. Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements.

There have been no changes to our critical accounting policies from those disclosed in our Form 10-K for the year ended December 31, 2011.

Recently Issued Accounting Pronouncements

In May 2011, the FASB issued Accounting Standards Update (“ASU”) Number 2011-04, amending Topic 820 – Fair Value Measurement, which the Company adopted on January 1, 2012. ASU Number 2011-04 changes certain fair value measurement principles and clarifies the application of existing fair value measurement guidance. Amendments include limiting the concepts of valuation premise and highest and best use to the measurement of nonfinancial assets. ASU Number 2011-04 also requires additional fair value disclosures including a qualitative discussion about the sensitivity of recurring Level 3 fair value measurements and the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed. This guidance did not have a significant impact on the Company’s financial statements.

In June 2011, the FASB issued Accounting Standards Update (“ASU”) Number 2011-05, amending Topic 220 – Comprehensive Income, which the Company adopted on January 1, 2012. The ASU modifies alternative presentation standards, eliminating the option for disclosure of the elements of other comprehensive income within the statement of stockholder’s equity. Adoption of this ASU by the Company changed our existing presentation, but did not impact the components of other comprehensive income and accordingly did not have a material impact on the Company’s consolidated financial statements. In December 2011, the FASB issued ASU Number 2011-12, which defers the effective date of amendments to the presentation of reclassifications of items out of accumulated other comprehensive income in ASU Number 2011-05. This ASU supersedes certain pending paragraphs in ASU Number 2011-05.

 

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to a variety of market risks including credit risk, commodity price risk and interest rate risk. We address these risks through a program of risk management which may include the use of derivative instruments.

Commodity Price Risk

Our primary market risk exposure is in the pricing applicable to our crude oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our United States natural gas production. Pricing for crude oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production for the three months ended March 31, 2012, our annual revenue would increase or decrease by approximately $10.2 million for each $10.00 per barrel change in crude oil prices and $18.9 million for each $1.00 per MMBtu change in natural gas prices.

To partially reduce price risk caused by these market fluctuations, we hedge a portion of our anticipated crude oil and natural gas production as part of our risk management program. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and more price sensitive drilling programs. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. While hedging limits the downside risk of adverse price movements, it also may limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty.

For a further discussion of our hedging activities including a list of the commodity derivatives held by the Company, please see “Notes to Unaudited Condensed Consolidated Financial Statements — Note 3, Fair Value Measurements” and “Notes to Unaudited Condensed Consolidated Financial Statements — Note 5, Commodity Derivative Instruments and Hedging Activities” included in this report.

Credit Risk

We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through joint interest receivables ($4.7 million at March 31, 2012) and the sale of our crude oil and natural gas production, which we market to energy marketing companies, refineries and affiliates ($28.1 million in receivables at March 31, 2012). Joint interest receivables arise from billing entities who own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. In order to minimize our exposure to credit risk we request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. In this manner, we reduce credit risk. We also have the right to place a lien on our co-owners interest in the well to redirect production proceeds in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.

We monitor our exposure to counterparties on crude oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to support crude oil and natural gas sales receivables owed to us.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. We have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this Quarterly Report on Form 10-Q. Based

 

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upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2012 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting. This report does not include a report of management’s assessment regarding internal control over financial reporting due to a transition period established by the SEC for newly public companies.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

In the ordinary course of business, we are involved in various pending or threatened legal actions. While management is unable to predict the ultimate outcome of any of these actions, it believes that any ultimate liability arising from these actions will not have a material adverse effect on our consolidated financial position, results of operations or cash flows; however, because of the inherent uncertainty of litigation, we cannot provide assurance that the resolution of any particular claim or proceeding to which we are a party will not have a material adverse effect on our financial position, results of operation or cash flows.

Item 1A. Risk Factors

Recently approved final rules regulating air emissions from natural gas production operations could cause us to incur increased capital expenditures and operating costs, which may be significant.

On April 17, 2012, the EPA approved final regulations under the Clean Air Act that, among other things, require additional emissions controls for natural gas and natural gas liquids production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. The final regulations require the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as flares, in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage tanks and other production equipment. We are currently reviewing this new rule and assessing its potential impacts. Compliance with these requirements could increase our costs of development and production, though we do not expect these requirements to be any more burdensome to us than to other similarly situated companies involved in oil and natural gas exploration and production activities.

In addition to the information set forth in this Form 10-Q, you should carefully consider the factors discussed in Part I, Item 1A. Risk Factors in our 2011 Form 10-K that was filed with the SEC on March 27, 2012, which could materially affect our business, financial condition or future results. You should also consider the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements.” Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially and adversely affect our business. If any of these risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected.

Item 6. Exhibits

The exhibits required to be filed pursuant to Item 601 of Regulation S-K are set forth in the Exhibit Index accompanying this report and are incorporated herein by reference.

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

RAAM Global Energy Company    
May 11, 2012     By:   RAAM Global Energy Company
      By: /s/ Jeffrey Craycraft
      Jeffrey Craycraft
      Chief Financial Officer
      (Duly Authorized Officer and Principal Financial Officer)

 

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Exhibit Index

 

3.1   Certificate of Incorporation of RAAM Global Energy Company, dated November 19, 2003 (incorporated by reference from Exhibit 3.1 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
3.2   Bylaws of RAAM Global Energy Company (incorporated by reference from Exhibit 3.2 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
31.1 *   Certification of Chief Executive Officer Pursuant to Rule 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Amended.
31.2 *   Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Amended.
32.1 **   Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2 **   Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
101***   Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Condensed Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011; (ii) our Condensed Consolidated Statements of Operations for the three months ended March 31, 2012 and 2011; (iii) our Condensed Consolidated Statements of Comprehensive Income for the three months ended March 31, 2012 and 2011; (iv) our Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2012 and 2011; and (v) the notes to our Condensed Consolidated Financial Statements.

 

* Filed herewith.
** Furnished herewith.
*** Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under those sections.

 

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