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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 SEPTEMBER 30, 2011

  ¨

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 November 11, 2011, there were 60,000 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 Cash Flows

     8   

Notes to Unaudited Condensed Consolidated Financial Statements

     9   

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

     27   

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     37   

Item 4. Controls and Procedures

     38   

Part II. Other Information

  

Item 1. Legal Proceedings

     38   

Item 1A. Risk Factors

     39   

Item 6. Exhibits

     40   

SIGNATURES

     41   

Exhibit Index

     42   

 

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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, or 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 (1) Part II, “Item 1A. Risk Factors” and elsewhere in this report and (2) the risk factors described in our registration statement on Form S-4 (File No. 333-172897) filed with the SEC on March 17, 2011 (“Form S-4”).

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)

 

    

    September 30,    

 

2011

    

    December 31,    

 

2010

 
  

 

 

 

Assets

     

Current assets:

     

Cash and cash equivalents

       $ 87,014             $ 81,032     

Accounts receivable, net of $1,005 and $235 provision for bad debts in 2011 and 2010, respectively

     4,860           22,412     

Revenues receivable

     32,222           21,703     

Income taxes receivable

     4,142           2,955     

Commodity derivatives – current portion

     7,420           9,377     

Prepaid assets

     7,932           4,200     

Other current assets

     4,248           3,784     
  

 

 

 

Total current assets

     147,838           145,463     

Oil and gas properties (full-cost method):

     

Properties being amortized

     1,138,012           1,009,071     

Properties not subject to amortization

     74,152           81,656     

Less accumulated depreciation, depletion, and amortization

     (697,081)           (653,777)     
  

 

 

 

Net oil and gas properties

     515,083           436,950     

Other assets:

     

Other capitalized assets, net

     7,197           7,246     

Commodity derivatives

     1,983           263     

Equity investments

     –           2,044     

Other

     19,090           5,320     
  

 

 

 

Total other assets

     28,270           14,873     
  

 

 

 

Total assets

       $ 691,191             $ 597,286     
  

 

 

 

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)

 

    

    September 30,    

 

2011

    

    December 31,    

 

2010

 
  

 

 

 

Liabilities and shareholders’ equity

     

Current liabilities:

     

Accounts payable and accrued liabilities

       $ 29,556             $ 19,587     

Revenues payable

     30,304           17,834     

Interest payable - senior secured notes

     –           5,048     

Current taxes payable

     2,217           924     

Advances from joint interest partners

     1,003           –     

Commodity derivatives - current portion

     564           1,973     

Asset retirement obligations - current portion

     428           2,406     

Long-term debt – current portion

     3,720           1,112     

Deferred income taxes – current portion

     357           1,810     
  

 

 

 

Total current liabilities

     68,149           50,694     

Noncurrent liabilities:

     

Commodity derivatives

     –           861     

Asset retirement obligations

     23,834           20,946     

Long-term debt

     2,754           2,860     

Senior secured notes

     199,974           148,681     

Deferred income taxes

     107,861           90,870     
  

 

 

 

Total noncurrent liabilities

     334,423           264,218     
  

 

 

 

Total liabilities

     402,572           314,912     

Commitments and contingencies (see Note 11)

     

Noncontrolling interest

     –           2,467     

Shareholders’ equity:

     

Common stock, no par value, 380,000 shares authorized, 60,000 outstanding in 2011 and 2010

     56,146           56,096     

Treasury stock, 5,166 shares in 2011 and 2010

     (5,736)           (5,736)     

Accumulated other comprehensive income, net of taxes

     7,396           5,977     

Retained earnings

     230,813           223,570     
  

 

 

 

Total shareholders’ equity

     288,619           279,907     
  

 

 

 

Total liabilities and shareholders’ equity

       $ 691,191             $ 597,286     
  

 

 

 

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 September 30            Nine Months Ended September 30      
    

 

 

 
      

2011

      

2010

      

2011

      

2010

 

Revenues:

                   

Gas sales

       $    26,770             $ 23,277         $ 76,194                  $ 91,865     

Oil sales

       27,284               17,983           74,190            60,980     
    

 

 

 

Total revenues

       54,054               41,260           150,384            152,845     

Costs and expenses:

                   

Production and delivery costs

       8,156               6,830           24,508            21,642     

Workover costs

       4,568               3,990           5,786            6,057     

Depreciation, depletion and amortization

       13,387               19,741           44,450            59,283     

General and administrative expenses

       4,815               3,892           13,159            10,283     

Bad debt expense

       –                         770            –     

Derivative expense

       822               37           283            345     
    

 

 

 

Total operating expense

       31,748               34,490           88,956            97,610     
    

 

 

 

Income from operations

       22,306               6,770           61,428            55,235     

Other income (expenses):

                   

Interest expense, net

       (5,437)               (1,665)           (11,785)            (3,302)     

Loss from equity investment

       (2,044)                         (2,044)            –     

Other, net

       (30)               6           151            541     
    

 

 

 

Total other income (expenses)

       (7,511)               (1,659)           (13,678)            (2,761)     
    

 

 

 

Income before taxes

       14,795               5,111           47,750            52,474     

Income tax provision

       5,480               1,980           17,490            19,194     
    

 

 

 

Net income including noncontrolling interest

       $    9,315             $ 3,131         $     30,260                  $ 33,280     
    

 

 

 

Net income (loss) attributable to noncontrolling interest (net of tax)

       (3)               234           1,476            1,180     
    

 

 

 

Net income attributable to RAAM Global

       $    9,318             $ 2,897         $ 28,784                  $ 32,100     
    

 

 

 

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)

 

             Nine Months Ended September 30           
    

2011

    

2010

 

Operating activities

     

Net income including noncontrolling interest

       $ 30,260       $ 33,280      

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

     

Depreciation, depletion and amortization

     45,841         60,394      

Deferred income taxes

     15,538         1,371      

Loss on disposal of inventory and properties

     20         –      

Loss from equity method investment

     2,044         –      

Changes in components of working capital:

     

Accounts and revenues receivable

     7,033         11,077      

Insurance receivable

             6,050      

Income tax receivables

     (1,188)         (3,941)      

Other current assets

     (3,867)         (1,969)      

Change in derivatives, net

     (614)         3,640      

Accounts payable and accrued liabilities

     10,212         (17,297)      

Current taxes payable

     1,293         (304)      

Interest payable on Senior Notes

     (5,048)         361      

Revenues payable

     12,470         (4,156)      
  

 

 

 

Net cash provided by operating activities

     113,994         88,506      

Investing activities

     

Change in investments

             149      

Change in advances from joint interest partners

     1,003         (1,052)      

Payment of prepaid drilling expenses

     (14,000)         –      

Additions to oil and gas properties and equipment

     (123,925)         (42,106)      

Purchase of noncontrolling interest

     (21,000)         –      

Proceeds from net sales of oil and gas properties

     2,125         –      
  

 

 

 

Net cash used in investing activities

     (155,797)         (43,009)      

Financing activities

     

Proceeds from long-term borrowings

     8,037         8,874      

Payments on long-term borrowings

     (5,534)         (115,017)      

Proceeds from issuance of 12.5% Senior Notes due 2015

     51,250         148,629      

Deferred bond costs

     (1,468)         (6,493)      

Payment of dividends

     (4,500)         (4,500)      
  

 

 

 

Net cash provided by financing activities

     47,785         31,493      
  

 

 

 

Increase in cash and cash equivalents

     5,982         76,990      

Cash and cash equivalents, beginning of period

     81,032         28,888      
  

 

 

 

Cash and cash equivalents, end of period

       $ 87,014       $ 105,878      
  

 

 

 

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 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, its majority-owned joint venture and variable interest entities where RAAM Global is the primary beneficiary. Significant 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 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, 2010, 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 financial statements included in our registration statement on Form S-4 (File No. 333-172897) filed with the Securities and Exchange Commission (“SEC”).

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 $1.2 million and $1.0 million for the three months ended September 30, 2011 and 2010, respectively, and these costs amounted to $3.7 million and $2.8 million for the nine months ended September 30, 2011 and 2010, respectively.

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 $74.2 million and $81.7 million at September 30, 2011 and December 31, 2010, respectively. The Company believes that the unevaluated properties at September 30, 2011 will be substantially evaluated during 2012 and 2013, and the costs will begin to be amortized at that time. The Company capitalized interest of $1.1 million and $0.1 million during the three months ended September 30, 2011 and 2010, respectively, related to significant properties not subject to amortization. The Company capitalized interest of $5.1 million and $0.5 million during the nine months ended September 30, 2011 and 2010, respectively, related to significant properties not subject to amortization.

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. Details specific to the Company’s ceiling tests for the periods presented in the accompanying condensed consolidated financial statements are discussed later in this footnote section.

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 final sales price amounted to $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 is recorded as a reduction to net oil and gas properties with no income statement impact because the original cost of the acreage is not a significant percentage of the Company’s consolidated capitalized costs. The cash payment was collected during May 2011.

During the second quarter of 2011, the Company entered into an agreement with an unrelated third party to acquire a 40% working interest in drilling activities in Oklahoma. The Company prepaid $14 million in drilling expenses for this program. This prepayment is recorded in Other, in the Other assets section of the condensed consolidated balance sheet. The third party we have entered into the agreement with will send the Company joint interest billing information on a periodic basis reflecting the amount of our prepayment that has been utilized for drilling activities. Based on this information, the prepayment will be reduced by the amount of utilization and be transferred from Other into Oil and gas properties. As of September 30, 2011, the $14 million prepayment remained in Other, in the Other assets section of the condensed consolidated balance sheet.

In January 2010, the Company adopted the Financial Accounting Standards Board (“FASB”) guidance on oil and gas reserve estimation and disclosures. This guidance amends previous FASB guidance on oil and gas extractive activities to align the accounting requirements with the Securities and Exchange Commission’s final rule, Modernization of the Oil and Gas Reporting Requirements issued on December 31, 2008. In summary, the revisions in this guidance modernize the disclosure rules to better align with current industry practices and expand the disclosure requirements for equity method investments so that more useful information is provided. More specifically, the main provisions include the following:

 

   

An expanded definition of oil and gas producing activities to include nontraditional resources such as bitumen extracted from oil sands.

 

   

The use of an average of the first-day-of-the-month price for the 12-month period, rather than a year-end price for determining whether reserves can be produced economically.

 

   

Amended definitions of key terms such as “reliable technology” and “reasonable certainty” which are used in estimating proved oil and gas reserve quantities.

 

   

A requirement for disclosing separate information about reserve quantities and financial statement amounts for geographical areas representing 15 percent or more of proved reserves.

 

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Clarification that an entity’s equity investments must be considered in determining whether it has significant oil and gas activities and a requirement to disclose equity method investments in the same level of detail as is required for consolidated investments.

The new rules are considered a change in accounting principle that is inseparable from a change in accounting estimate, which does not require retroactive revision. This change in accounting principle has had a material effect on the consistency of the Company’s oil and gas reserve estimates, supplemental disclosures, the calculation of DD&A and the full-cost ceiling test. At September 30, 2011, the Company’s ceiling test computation did not result in a write-down and was based on twelve-month average prices of $91.00 per barrel of oil and $4.16 per MMBtu of natural gas. At December 31, 2010, the Company’s ceiling test computation did not result in a write-down and was based on twelve-month average prices of $75.96 per barrel of oil and $4.38 per MMBtu of natural gas.

There are certain related party entities that are joint interest and revenue partners in certain of the Company’s properties. See Note 10 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 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 instruments entered into in 2011 and 2010 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. Hedge ineffectiveness of 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 September 30, 2011 and 2010, 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 $4.3 million and $0.8 million, respectively, net of tax effects. During the nine months ended September 30, 2011 and 2010, the amounts of other comprehensive income (loss) related to hedge transactions that settled and were recorded in the accompanying condensed consolidated statements of operations were a loss of $0.4 million and income of $4.9 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 and be recorded in the 2011 and 2012 consolidated statements of operations will be $4.5 million, net of tax effects.

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 September 30, 2011 and December 31, 2010 were $19.0 million and $18.8 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 within depreciation, depletion and amortization on the accompanying condensed consolidated statement of operations.

 

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

 

In thousands       

Balance of ARO as of January 1, 2011

     $                    23,352     

Accretion expense

     667     

Additions

     969     

Settlement of ARO

     (750)     

Changes in ARO estimate

     24     
  

 

 

 

Balance of ARO as of September 30, 2011

       $                    24,262     
  

 

 

 

Operating Segments

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

New Accounting Pronouncements

ASU Number 2011-5 was issued in June 2011, amending Topic 220 – Comprehensive Income. 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 will change our existing presentation, but will not impact the components of other comprehensive income. The ASU is effective for fiscal periods beginning after December 15, 2011.

 

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.

 

   

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 September 30, 2011 and December 31, 2010, 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).

 

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     Fair Value Measurements Using Significant
Other Observable Inputs (Level 2)
 
Description    September 30, 2011      December 31, 2010  
In thousands              

Assets:

     

Fair value of commodity derivatives - current assets

     $     7,420       $     9,377     

Fair value of commodity derivatives - long-term assets

     1,983         263     
  

 

 

 

Total Assets

     $ 9,403       $ 9,640     
  

 

 

 

Liabilities:

     

Fair value of commodity derivatives - current liabilities

     $ (564)       $ (1,973)     

Fair value of commodity derivatives - long-term liabilities

             (861)     
  

 

 

 

Total Liabilities

     $ (564)       $ (2,834)     
  

 

 

 

2015 Senior Secured Notes

During September 2010 and July 2011, the Company issued Senior Secured Notes. At September 30, 2011, the fair value of the Notes was estimated to be $201.5 million, based on the prices the bonds have recently been quoted at in the market. As of September 30, 2011, 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 September 30, 2011.

 

4.

Accounts and Revenues Receivable

Accounts and revenues receivable at September 30, 2011 and December 31, 2010 were $37.1 million and $44.1 million, respectively, all of which were due from companies in the oil and gas industry. Of the revenues receivable, $28.2 million and $19.7 million were due from five companies at September 30, 2011 and December 31, 2010, respectively.

Since all of RAAM Global’s accounts receivable from purchasers and joint interest owners at September 30, 2011 and December 31, 2010 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 September 30, 2011 and December 31, 2010. Management obtains letters of credit from its major purchasers and continually evaluates the creditworthiness of its partners.

 

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

 

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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 these transactions were designated as hedges, the Company is required to record the changes in fair value of these transactions as Other Comprehensive Income in the accompanying condensed consolidated balance sheets with the ineffective portion of the change in fair value reported as Derivative expense 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 September 30, 2011 and 2010, the Company realized a net increase in oil and gas revenues related to hedging transactions of approximately $1.4 million and $6.4 million, respectively. For the nine months ended September 30, 2011 and 2010, the Company realized a net increase in oil and gas revenues related to hedging transactions of approximately $8.1 million and $32.3 million, respectively. Hedge ineffectiveness was $822,000 and $37,000 for the three months ended September 30, 2011 and 2010, respectively. Hedge ineffectiveness was $283,000 and $345,000 for the nine months ended September 30, 2011 and 2010, respectively.

As of September 30, 2011, the Company held the commodity derivative instruments shown below related to the forecasted sale of its U.S. Gulf Coast natural gas production for 2011, 2012 and 2013:

 

          Volume in      NYMEX  
     Contract    MMBtus/      Strike  
            Remaining Contract Term    Type    Month      Price  

  October 2011

   Swap      93,000       $             4.60     

  October 2011

   Swap      93,000       $             4.80     

  October 2011

   Swap      155,000       $             4.50     

  October 2011 - December 2011

   Swap      100,000       $             6.24     

  October 2011 - December 2011

   Swap      100,000       $             6.33     

  November 2011 - December 2011

   Swap      91,500       $             4.85     

  November 2011 - December 2011

   Swap      91,500       $             4.85     

  November 2011 - February 2012

   Call      151,250       $             5.60     

  November 2011 - February 2012

   Put      151,250       $             5.00     

  November 2011 - February 2012

   Put      151,250       $             4.00     

  January 2012 - February 2012

   Swap      100,000       $             6.24     

  January 2012 - February 2012

   Swap      100,000       $             6.33     

  January 2012 - December 2012

   Swap      61,000       $             5.05     

  January 2012 - December 2012

   Swap      61,000       $             5.00     

  March 2012 - December 2012

   Put      153,000       $             3.75     

  March 2012 - December 2012

   Put      153,000       $             5.00     

  March 2012 - December 2012

   Call      153,000       $             6.15     

  January 2013 - December 2013

   Swap      152,083       $             5.40     

  January 2013 - December 2013

   Put      152,083       $             4.00     

  January 2013 - December 2013

   Call      152,083       $             5.40     

  January 2013 - December 2013

   Call      152,083       $             6.00     

 

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As of September 30, 2011, the Company held the commodity derivative instruments shown below related to the forecasted sale of its U.S. Gulf Coast oil production for 2011, 2012, 2013 and 2014:

 

        Remaining Contract Term   

Contract

 

Type

  

Volume in

 

BBls/

 

Month

    

NYMEX

 

Strike

 

Price

 

  October 2011 - December 2011

   Swap      6,000       $         86.76   

  October 2011 - December 2011

   Swap      6,000       $ 85.70   

  October 2011 - December 2011

   Swap      10,000       $ 85.25   

  October 2011 - December 2011

   Swap      8,000       $ 88.20   

  October 2011 - December 2011

   Swap      9,000       $ 85.50   

  October 2011 - December 2011

   Call      30,667       $ 95.00   

  October 2011 - December 2011

   Call      30,667       $ 86.21   

  October 2011 - December 2011

   Spread Swap      46,000       $ 17.25   

  January 2012 - March 2012

   Spread Swap      30,334       $ 16.75   

  January 2012 - March 2012

   Swap      10,000       $ 89.00   

  January 2012 - March 2012

   Swap      8,000       $ 88.24   

  January 2012 - March 2012

   Swap      6,000       $ 86.80   

  January 2012 - September 2012

   Swap      24,356       $ 82.25   

  January 2012 - December 2012

   Put      3,660       $ 110.00   

  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   

  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 derivatives can be referenced in Note 3, Fair Value Measurements.

 

6.

Equity Method Investments

Attune Australia

In November 2007, the Company purchased a 50% interest in Attune Australia LLC (“Attune”) for $7.2 million from RAAM Exploration LLC. Concordia Resources Inc., a related party, owns the remaining 50% of Attune Australia LLC. Attune’s operations consist of its ownership of an overriding royalty interest in an Australian oil field that began producing oil in November 2007. Due to the Company’s ability to exercise significant influence on this entity, the Company has accounted for the investment in Attune using the equity method.

The Company evaluates its equity method investments on a quarterly basis to ensure proper accounting treatment is being applied. During the Company’s equity method investment review in the third quarter of 2011, new

 

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information regarding this investment was identified indicating that the joint venture which had been operating this oil field was no longer in a stable financial position and it appears unlikely that there will be production from this oil field in the foreseeable future. Given that there is no expected revenue stream from this investment, the Company believes that the investment has incurred an other than temporary impairment (“OTTI”) and should be written down to zero. The result of this analysis was a $2.0 million OTTI charge, which was recorded in the Consolidated Statements of Operations in Loss from Equity Method Investments.

 

7.

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 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, although they bear a different CUSIP number than the Original Notes until they are no longer restricted securities under the Securities Act of 1933. On October 18, 2011, the Company initiated an exchange offer to register all of the Additional Notes that expires on November 18, 2011, unless extended by the Company.

As of September 30, 2011, 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 September 30, 2011. At September 30, 2011, the fair value of the Notes was estimated to be $201.5 million, based on the prices the bonds 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 September 24, 2010, an amendment to the Company’s Revolving Credit Facility established a new borrowing base of $62.5 million which was undrawn at September 30, 2011. 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. As of September 30, 2011, the Company was in compliance with all covenants under this agreement.

 

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Promissory Note

The Company has a promissory note with GE Commercial Finance Business Property Corporation (“GECF”) with a balance of $2.9 million at September 30, 2011 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 requires monthly installments of principal and interest in the amount of $0.9 million until February 1, 2012. There are no covenant requirements under this agreement.

 

8.

Income Taxes

The Income tax provision for the three months ended September 30, 2011 was $5.5 million or an effective tax rate of 37.0%, compared to $2.0 million or an effective tax rate of 38.7% for the three months ended September 30, 2010. The Income tax provision for the nine months ended September 30, 2011 was $17.5 million or an effective tax rate of 36.6%, compared to $19.2 million or an effective tax rate of 36.6% for the nine months ended September 30, 2010.

 

9.

Shareholders’ Equity

During 2011, dividends were paid at $25.00 per share to shareholders of record as of March 1, 2011, June 15, 2011 and September 15, 2011. During 2010, dividends were paid at $25.00 per share to shareholders of record effective March 15, 2010, June 15, 2010 and September 1, 2010.

 

10.

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 $1.1 million and $734,000 at September 30, 2011 and December 31, 2010, 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 $8.5 million and $4.5 million at September 30, 2011 and December 31, 2010, respectively, are included in Revenues payable in the Company’s condensed consolidated balance sheets and represent revenue owner payables.

 

11.

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 these matters will have a material adverse effect on the financial position, cash flows or results of operations of the Company.

 

12.

Other Comprehensive Income

The Company had Other comprehensive income of $15.1 million and $1.4 million for the three months ended September 30, 2011 and 2010, respectively. The Company had Other comprehensive income of $30.2 million and $26.2 million for the nine months ended September 30, 2011 and 2010, respectively.

 

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13.

Condensed Consolidating Financial Information

The following condensed consolidating financial information is presented in accordance with SEC regulation S-X requirements relating to multiple subsidiary guarantors of securities issued by the parent company of those subsidiaries. During 2010 RAAM Global issued the Original Notes and during 2011 RAAM Global issued the Additional Notes, described in Note 7, Debt. Each of RAAM Global’s wholly owned subsidiaries are guarantors of the Notes. The guarantees are full and unconditional and joint and several.

The following tables present condensed consolidating balance sheets as of September 30, 2011 and December 31, 2010, condensed consolidating statements of operations for the three and nine months ended September 30, 2011 and 2010 and condensed consolidating statements of cash flows for the nine months ended September 30, 2011 and 2010, and should be read in conjunction with the condensed consolidated financial statements herein.

 

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Condensed Consolidating Balance Sheets

At September 30, 2011

 

    RAAM Global
Energy Company
    Subsidiary
Guarantors
    Subsidiary
Non-guarantor
    Non-guarantor
VIEs
    Eliminations     Consolidated      

Assets

           

Current assets:

           

Cash and cash equivalents

      $ 69,029          $ 17,804      $ 167      $ 14      $      $ 87,014     

Receivables, net

    3,983            45,274               32        (8,065)        41,224     

Commodity derivatives – current portion

    –            7,420                             7,420     

Prepaids and other current assets

    1,909            10,271                             12,180     
 

 

 

 

Total current assets

    74,921            80,769        167        46        (8,065)        147,838     

Net oil and gas properties

    50,786            447,977        8,233        8,087               515,083     

Total other assets

    32,311            240,589                      (244,630)        28,270     
 

 

 

 

Total assets

      $ 158,018          $         769,335      $         8,400      $     8,133      $ (252,695)      $ 691,191     
 

 

 

 

Liabilities and shareholders’ equity

           

Current liabilities:

           

Payables and accrued liabilities

      $ 1,359          $ 60,605      $ 31      $ 8,147      $ (8,065)      $ 62,077     

Advances from joint interest partners

    –            1,003                             1,003     

Commodity derivatives – current portion

    –            564                             564     

Asset retirement obligations – current portion

    –            428                             428     

Long-term debt – current portion

    126            3,594                             3,720     

Deferred income taxes – current portion

    –            357                             357     
 

 

 

 

Total current liabilities

    1,485            66,551        31        8,147        (8,065)        68,149     

Noncurrent liabilities:

           

Asset retirement obligations

    875            22,708        172        79               23,834     

Long-term debt

    2,754                                        2,754     

Senior secured notes

    199,974                                        199,974     

Deferred income taxes

    5,199            101,252        1,410                      107,861     
 

 

 

 

Total noncurrent liabilities

    208,802            123,960        1,582        79               334,423     

Total liabilities

    210,287            190,511        1,613        8,226        (8,065)        402,572     

Total shareholders’ equity

    (52,269)            578,824        6,787        (93)        (244,630)        288,619     
 

 

 

 

Total liabilities and shareholders’ equity

      $               158,018          $ 769,335      $ 8,400      $ 8,133      $ (252,695)      $ 691,191     
 

 

 

 

 

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Condensed Consolidating Balance Sheets

At December 31, 2010

 

     RAAM Global
Energy Company
     Subsidiary
Guarantors
     Non-guarantor
VIEs
     Eliminations      Consolidated      

Assets

              

Current assets:

              

Cash and cash equivalents

       $ 45,683           $ 35,320       $ 29       $       $ 81,032     

Receivables, net

     3,491             52,019         528         (8,968)         47,070     

Commodity derivatives – current portion

     –             9,377                         9,377     

Prepaids and other current assets

     1,724             6,260                         7,984     
  

 

 

 

Total current assets

     50,898             102,976         557         (8,968)         145,463     

Net oil and gas properties

     55,808             370,000         11,142                 436,950     

Total other assets

     34,444             270,496                 (290,067)         14,873     
  

 

 

 

Total assets

       $ 141,150           $           743,472       $ 11,699       $ (299,035)       $ 597,286     
  

 

 

 

Liabilities and shareholders’ equity

              

Current liabilities:

              

Payables and accrued liabilities

       $ 6,423           $ 37,490       $ 8,448       $ (8,968)       $ 43,393     

Commodity derivatives – current portion

     –             1,973                         1,973     

Asset retirement obligations – current portion

     –             2,406                         2,406     

Long-term debt – current portion

     110             1,002                         1,112     

Deferred income taxes – current portion

     –             1,810                         1,810     
  

 

 

 

Total current liabilities

     6,533             44,681         8,448         (8,968)         50,694     

Noncurrent liabilities:

              

Commodity derivatives

     –             861                         861     

Asset retirement obligations

     872             19,923         151                 20,946     

Long-term debt

     2,860                                     2,860     

Senior secured notes

     148,681                                     148,681     

Deferred income taxes

     5,198             84,827         845                 90,870     
  

 

 

 

Total noncurrent liabilities

     157,611             105,611         996                 264,218     

Total liabilities

     164,144             150,292         9,444         (8,968)         314,912     

Noncontrolling interest

     –                     2,467                 2,467     

Total shareholders’ equity

     (22,994)             593,180         (212)         (290,067)         279,907     
  

 

 

 

Total liabilities and shareholders’ equity

       $               141,150           $ 743,472       $ 11,699       $ (299,035)       $ 597,286     
  

 

 

 

 

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Condensed Consolidating Statements of Operations

For the three months ended September 30, 2011

 

         RAAM Global
    Energy Company
     Subsidiary
Guarantors
     Non-guarantor
Subsidiary
     Non-guarantor
VIEs
     Eliminations      Consolidated      
  

 

 

 

Revenues:

                 

Gas sales

       $ 193       $ 25,322       $ 1,255       $             –         $             –         $     26,770     

Oil sales

     259         25,713         1,312         –           –           27,284     
  

 

 

 

Total revenues

     452         51,035         2,567         –           –           54,054     

Costs and expenses:

                 

Production and delivery costs

     99         7,920         137         –           –           8,156     

Workover costs

     20         4,489         59         –           –           4,568     

Depreciation, depletion and amortization

     1,118         12,266         1         2           –           13,387     

General and administrative expenses

     1,364         3,450                 1           –           4,815     

Derivative expense

             822                 –           –           822     
  

 

 

 

Total operating expense

     2,601         28,947         197         3           –           31,748     
  

 

 

 

Income from operations

     (2,149)         22,088         2,370         (3)           –           22,306     

Other income (expenses):

                 

Interest expense, net

     (5,329)         (108)                 –           –           (5,437)     

Loss from equity investment

     (2,044)                         –           –           (2,044)     

Other, net

             (30)                 –           –           (30)     
  

 

 

 

Total other income (expenses)

     (7,373)         (138)                 –           –           (7,511)     
  

 

 

 

Income (loss) before taxes

     (9,522)         21,950         2,370         (3)           –           14,795     

Income tax provision

     (1,050)         6,526         4         –           –           5,480     
  

 

 

 

Net income (loss) including noncontrolling interest

       $ (8,472)       $ 15,424       $ 2,366       $ (3)           $            –         $ 9,315     
  

 

 

 

Net loss attributable to noncontrolling interest (net of tax)

                             (3)           –           (3)     
  

 

 

 

Net income (loss) attributable to RAAM Global

       $     (8,472)       $     15,424       $ 2,366       $ –           $            –         $ 9,318     
  

 

 

 

 

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Condensed Consolidating Statements of Operations

For the three months ended September 30, 2010

 

         RAAM Global
    Energy Company
     Subsidiary
Guarantors
     Non-guarantor
VIEs
     Eliminations      Consolidated      
  

 

 

 

Revenues:

              

Gas sales

       $ 180       $ 22,451       $ 646       $ –         $ 23,277     

Oil sales

     207         17,267         509         –           17,983     
  

 

 

 

Total revenues

     387         39,718         1,155         –           41,260     

Costs and expenses:

              

Production and delivery costs

     76         6,668         86         –           6,830     

Workover costs

     2         3,988                 –           3,990     

Depreciation, depletion and amortization

     2,811         16,380         550         –           19,741     

General and administrative expenses

     1,126         2,766                 –           3,892     

Derivative expense

             37                 –           37     
  

 

 

 

Total operating expense

     4,015         29,839         636         –           34,490     
  

 

 

 

Income from operations

     (3,628)         9,879         519         –           6,770     

Other income (expenses):

              

Interest expense, net

     (577)         (1,088)                 –           (1,665)     

Other, net

     7         (1)                 –           6     
  

 

 

 

Total other income (expenses)

     (570)         (1,089)                 –           (1,659)     
  

 

 

 

Income (loss) before taxes

     (4,198)         8,790         519         –           5,111     

Income tax provision

     4,500         (2,805)         285         –           1,980     
  

 

 

 

Net income (loss) including noncontrolling interest

   $ (8,698)       $ 11,595       $ 234       $ –         $ 3,131     
  

 

 

 

Net income attributable to noncontrolling interest (net of tax)

                     234         –           234     
  

 

 

 

Net income (loss) attributable to RAAM Global

       $     (8,698)       $     11,595       $       $             –         $     2,897     
  

 

 

 

 

22


Table of Contents

Condensed Consolidating Statements of Operations

For the nine months ended September 30, 2011

 

00000 00000 00000 00000 00000 00000
        RAAM Global
    Energy Company
    Subsidiary
Guarantors
    Non-guarantor
Subsidiary
    Non-guarantor
VIEs
    Eliminations     Consolidated      
 

 

 

 

Revenues:

           

Gas sales

          $ 589      $ 72,728      $ 1,255      $         1,622      $      $ 76,194     

Oil sales

    728        70,541        1,312        1,609               74,190     
 

 

 

 

Total revenues

    1,317        143,269        2,567        3,231               150,384     

Costs and expenses:

           

Production and delivery costs

    313        23,836        137        222               24,508     

Workover costs

    20        5,666        59        41               5,786     

Depreciation, depletion and amortization

    5,272        38,281        1        896               44,450     

General & administrative expenses

    3,932        9,219               8               13,159     

Bad debt expense

           770                             770     

Derivative expense

           283                             283     
 

 

 

 

Total operating expense

    9,537        78,055        197        1,167               88,956     
 

 

 

 

Income from operations

    (8,220)        65,214        2,370        2,064               61,428     

Other income (expenses):

           

Interest expense, net

    (11,523)        (262)                             (11,785)     

Loss from equity investment

    (2,044)                                    (2,044)     

Other, net

    184        (33)                             151     
 

 

 

 

Total other income (expenses)

    (13,383)        (295)                             (13,678)     
 

 

 

 

Income (loss) before taxes

    (21,603)        64,919        2,370        2,064               47,750     

Income tax provision

    950        15,948        4        588               17,490     
 

 

 

 

Net income (loss) including noncontrolling interest

          $         (22,553)      $     48,971      $ 2,366      $ 1,476      $      $ 30,260     
 

 

 

 

Net income attributable to noncontrolling interest (net of tax)

                         1,476               1,476     
 

 

 

 

Net income (loss) attributable to RAAM Global

          $ (22,553)      $ 48,971      $ 2,366      $      $             –      $     28,784     
 

 

 

 

 

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Table of Contents

Condensed Consolidating Statements of Operations

For the nine months ended September 30, 2010

 

        RAAM Global
    Energy Company
    Subsidiary
Guarantors
    Non-guarantor
VIEs
    Eliminations     Consolidated      
 

 

 

 

Revenues:

         

Gas sales

          $ 864      $ 89,148      $         1,853      $      $ 91,865     

Oil sales

    675        58,651        1,654               60,980     
 

 

 

 

Total revenues

    1,539        147,799        3,507               152,845     

Costs and expenses:

         

Production and delivery costs

    280        21,125        237               21,642     

Workover costs

    22        6,035                      6,057     

Depreciation, depletion and amortization

    8,442        49,190        1,651               59,283     

General and administrative expenses

    2,873        7,393        17               10,283     

Derivative expense

           345                      345     
 

 

 

 

Total operating expense

    11,617        84,088        1,905               97,610     
 

 

 

 

Income from operations

    (10,078)        63,711        1,602               55,235     

Other income (expenses):

         

Interest expense, net

    (661)        (2,641)                      (3,302)     

Other, net

    72        469                      541     
 

 

 

 

Total other income (expenses)

    (589)        (2,172)                      (2,761)     
 

 

 

 

Income (loss) before taxes

    (10,667)        61,539        1,602               52,474     

Income tax provision

    14,545        4,227        422               19,194     
 

 

 

 

Net income (loss) including noncontrolling interest

          $         (25,212)      $     57,312      $     1,180      $      $ 33,280     
 

 

 

 

Net income attributable to noncontrolling interest (net of tax)

                  1,180               1,180     
 

 

 

 

Net income (loss) attributable to RAAM Global

          $ (25,212)      $ 57,312      $      $             –      $     32,100     
 

 

 

 

 

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Table of Contents

Condensed Consolidating Statements of Cash Flows

For the nine months ended September 30, 2011

 

    RAAM Global
Energy Company
    Subsidiary
Guarantors
    Non-guarantor
Subsidiary
    Non-guarantor
VIEs
    Eliminations     Consolidated    
 

 

 

 

Net cash provided by (used in) operating activities

    $ (19,960)      $ 125,610      $ 2,536      $ 5,808      $      $ 113,994     

Investing activities

           

Change in investments between affiliates

    19,191        (17,070)        (2,121)                      –     

Change in advances from joint interest partners

           1,003                             1,003     

Payment of prepaid drilling expenses

           (14,000)                             (14,000)     

Additions to oil and gas properties and equipment

    (78)        (117,776)        (248)        (5,823)               (123,925)     

Purchase of noncontrolling interest

    (21,000)                                    (21,000)     

Proceeds from net sales of oil and gas properties

           2,125                             2,125     
 

 

 

 

Net cash used in investing activities

    (1,887)        (145,718)        (2,369)        (5,823)               (155,797)     

Financing activities

           

Proceeds from long-term borrowings

           8,037                             8,037     

Payments on long-term borrowings

    (89)        (5,445)                             (5,534)     

Proceeds from issuance of 12.5% Senior Notes due 2015

    51,250                                    51,250     

Deferred bond costs

    (1,468)                                    (1,468)     

Payment of dividends

    (4,500)                                    (4,500)     
 

 

 

 

Net cash provided by financing activities

    45,193        2,592                             47,785     
 

 

 

 

Increase (decrease) in cash and cash equivalents

    23,346        (17,516)        167        (15)               5,982     

Cash and cash equivalents, beginning of period

    45,683        35,320               29               81,032     
 

 

 

 

Cash and cash equivalents, end of period

    $           69,029      $         17,804      $     167      $ 14      $             –      $     87,014     
 

 

 

 

 

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Table of Contents

Condensed Consolidating Statements of Cash Flows

For the nine months ended September 30, 2010

 

     RAAM Global
Energy Company
     Subsidiary
Guarantors
     Non-guarantor
VIEs
     Eliminations      Consolidated    
  

 

 

 

Net cash provided by (used in) operating activities

     $ (18,485)       $ 104,619       $ 2,372       $       $ 88,506     

Investing activities

              

Change in investments

             149                         149     

Change in investments between affiliates

     (76,047)         76,047                         –     

Change in advances from joint interest partners

             (1,052)                         (1,052)     

Additions to oil and gas properties and equipment

     (172)         (39,555)         (2,379)                 (42,106)     
  

 

 

 

Net cash provided by (used in) investing activities

     (76,219)         35,589         (2,379)                 (43,009)     

Financing activities

              

Proceeds from long-term borrowings

             8,874                         8,874     

Payments on long-term borrowings

     (74)         (114,943)                         (115,017)     

Proceeds from issuance of 12.5% Senior Notes due 2015

     148,629                                 148,629     

Deferred bond costs

     (6,486)         (7)                         (6,493)     

Payment of dividends

     (4,500)                                 (4,500)     
  

 

 

 

Net cash provided by (used in) financing activities

     137,569         (106,076)                         31,493     
  

 

 

 

Increase (decrease) in cash and cash equivalents

     42,865         34,132         (7)                 76,990     

Cash and cash equivalents, beginning of period

     3,190         25,681         17                 28,888     
  

 

 

 

Cash and cash equivalents, end of period

     $           46,055       $         59,813       $     10       $             –       $       105,878     
  

 

 

 

 

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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 Form S-4. 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 Item 1A of this report, along with “Cautionary Statement Regarding Forward-Looking Statements” at the beginning of this report, and the risk factors described in our registration statement on Form S-4 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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Table of Contents

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.

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 and nine months ended September 30, 2011 and 2010.

 

           Three Months Ended September 30                Nine Months Ended September 30      
      

2011

      

2010

      

2011

      

2010

 

Average daily production:

                   

Oil (Bbl per day)

       3,187           2,667           2,858           3,038     

Natural gas (Mcf per day)

       54,167           38,779           47,700           44,941     

Oil equivalents (Boe per day)

       12,215           9,130           10,808           10,528     

Average prices: (1)

                   

Oil ($/Bbl)

         $ 91.30         $ 94.88         $ 97.65         $ 73.53     

Natural gas ($/Mcf)

         $ 5.48         $ 5.04         $ 5.70         $ 7.49     

Oil equivalents ($/Boe)

         $ 48.10         $ 49.12         $ 50.97         $ 53.18     

Production expense ($/Boe)

         $ 7.26         $ 8.13         $ 8.31         $ 7.53     

General and administrative expense ($/Boe)

         $ 4.28         $ 4.63         $ 4.46         $ 3.58     

Net income (in thousands)

         $         9,318         $ 2,897         $ 28,784         $ 32,100     

EBITDA (2) (in thousands)

         $ 33,692         $         26,350         $           102,693         $         114,040     

 

(1) 

Average prices presented give effect to our hedging. Please see “— Oil and Gas Hedging” 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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Table of Contents

The following table sets forth a reconciliation of net income as determined in accordance with U.S. GAAP to EBITDA for the periods indicated in thousands.

 

             Three Months Ended September 30              Nine Months Ended September 30      
  

 

 

 
    

2011

    

2010

      

2011

    

2010

 

In thousands

             

Net income

         $ 9,318       $ 2,897         $ 28,784       $ 32,100     

Interest expense

     5,507         1,732           11,969         3,463     

Depreciation, depletion and amortization

     13,387         19,741           44,450         59,283     

Income taxes

     5,480         1,980           17,490         19,194     
  

 

 

 

EBITDA

         $       33,692       $           26,350         $           102,693       $           114,040     
  

 

 

 

Results of Operations

The following table sets forth the unaudited results of operations for the three and nine months ended September 30, 2011 and 2010 in thousands.

 

           Three Months Ended September 30        Nine Months Ended September 30      
    

 

 

 
      

2011

      

2010

      

2011

      

2010

 

Revenues:

                   

Gas sales

       $    26,770             $ 23,277         $ 76,194         $ 91,865     

Oil sales

       27,284               17,983           74,190           60,980     
    

 

 

 

Total revenues

       54,054               41,260           150,384           152,845     

Costs and expenses:

                   

Production and delivery costs

       8,156               6,830           24,508           21,642     

Workover costs

       4,568               3,990           5,786           6,057     

Depreciation, depletion and amortization

       13,387               19,741           44,450           59,283     

General and administrative expenses

       4,815               3,892           13,159           10,283     

Bad debt expense

       –                         770           –     

Derivative expense

       822               37           283           345     
    

 

 

 

Total operating expense

       31,748               34,490           88,956           97,610     
    

 

 

 

Income from operations

       22,306               6,770           61,428           55,235     

Other income (expenses):

                   

Interest expense, net

       (5,437)               (1,665)           (11,785)           (3,302)     

Loss from equity investment

       (2,044)                         (2,044)           –     

Other, net

       (30)               6           151           541     
    

 

 

 

Total other income (expenses)

       (7,511)               (1,659)           (13,678)           (2,761)     
    

 

 

 

Income before taxes

       14,795               5,111           47,750           52,474     

Income tax provision

       5,480               1,980           17,490           19,194     
    

 

 

 

Net income including noncontrolling interest

       $    9,315             $ 3,131         $ 30,260         $ 33,280     
    

 

 

 

Net income (loss) attributable to noncontrolling interest (net of tax)

       (3)               234           1,476           1,180     
    

 

 

 

Net income attributable to RAAM Global

       $    9,318             $     2,897         $     28,784         $     32,100     
    

 

 

 

 

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

Revenues

Oil and natural gas production. Oil and natural gas production for the three months ended September 30, 2011 increased to 1.1 MMBoe from 0.8 MMBoe for the three months ended September 30, 2010. During the three months ended September 30, 2011, production from new discoveries in the Yegua area onshore Texas were offset by normal production declines in the more mature fields of West Cameron in the federal waters and in a mature well in Breton Sound 45 in Louisiana state waters. We also experienced downtime from mandated shut-ins of wells during tropical storms in the Gulf of Mexico.

Total revenues. Total revenues for the three months ended September 30, 2011 increased to $54.1 million from $41.3 million for the three months ended September 30, 2010. The increase in revenue was mainly attributable to higher volumes of oil and gas production, offset partially by a decrease in oil prices. The average sales price for the three months ended September 30, 2011 was $48.10 per Boe as compared to $49.12 per Boe for the three months ended September 30, 2010.

Operating costs and expenses

Production and delivery costs. Production and delivery costs were $8.2 million, or $7.26 per Boe, for the three months ended September 30, 2011, and $6.8 million, or $8.13 per Boe, for the comparable period in 2010. The increase in production and delivery costs was primarily attributable to more repair and maintenance costs and enhanced regulatory and compliance efforts required on our platforms.

Workover costs. Our workover costs for the three months ended September 30, 2011 were $4.6 million, or $4.06 per Boe, and $4.0 million in the comparable period of 2010, or $4.75 per Boe. The increase in workover costs from the comparable period in 2010 was primarily a result of changes in projects needed to manage our wells and maintain efficient production levels.

Depreciation, depletion and amortization. Depreciation, depletion and amortization for the three months ended September 30, 2011 decreased to $13.4 million from $19.7 million in the three months ended September 30, 2010. The decrease in depreciation, depletion and amortization was primarily due to a decrease in the depletion rate based on the calculation which uses higher future gross revenues on reserves existing in 2011 compared to 2010.

General and administrative expenses. General and administrative expense increased to $4.8 million during the three months ended September 30, 2011, from $3.9 million in the comparable period in 2010. The increase in general and administrative expense was primarily due to higher salaries and office rent from the establishment of a Denver office location, increased consultant compensation for the use of more specialized consultants on technical projects and additional accounting and legal fees incurred for regulatory compliance matters pursuant to the registration of the Additional Notes.

Interest expense. Net interest expense increased to $5.4 million for the three months ended September 30, 2011, from $1.7 million for the three months ended September 30, 2010 due to higher outstanding debt balances and interest rates associated with the issuance of the Notes in late September 2010 and mid-July 2011. Debt balances averaged $191.8 million during the three months ended September 30, 2011 and $103.3 million during the three months ended September 30, 2010. Interest rates averaged 12.5% during the three months ended September 30, 2011 and 4.17% during the three months ended September 30, 2010. The increase in interest rates was due to the issuance of the Notes and using a portion of the proceeds from the Original Notes offering to repay all of the outstanding indebtedness under the revolving credit facility.

Loss from equity investment. During the three months ended September 30, 2011, the Company recorded an OTTI charge of $2.0 million on our Attune Australia investment.

Income tax provision. For the three months ended September 30, 2011, the Company recorded income tax expense of $5.5 million as compared to income tax expense of $2.0 million for the three months ended September 30, 2010. Income tax expense recognized was based on an effective tax rate calculation of approximately 37.0% at September 30, 2011 and approximately 38.7% at September 30, 2010. Our effective tax rate differs from the statutory federal income tax rate primarily because of state and local income taxes, domestic production activities deductions, and percentage of depletion in excess of basis.

 

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

Revenues

Oil and natural gas production. Oil and natural gas production for the nine months ended September 30, 2011 increased to 3.0 MMBoe from 2.9 MMBoe for the nine months ended September 30, 2010. The increase in production during the period was mainly due to production from new discoveries during the second and third quarters of 2011 partially offset by normal production declines of more mature wells and mandated shut-ins during tropical storms in the Gulf of Mexico.

Total revenues. Total revenues for the nine months ended September 30, 2011 decreased to $150.4 million from $152.8 million for the nine months ended September 30, 2010. The decrease in revenue was mainly attributable to lower gas prices which were partially offset by the increase in oil prices. The average sales price for the nine months ended September 30, 2011 was $50.97 per Boe as compared to $53.18 per Boe for the nine months ended September 30, 2010.

Operating costs and expenses

Production and delivery costs. Production and delivery costs increased to $24.5 million, or $8.31 per Boe, for the nine months ended September 30, 2011, up from $21.6 million, or $7.53 per Boe, for the comparable period in 2010. The increase in production and delivery costs was primarily attributable to more repair and maintenance costs and enhanced regulatory and compliance efforts required on our platforms.

Workover costs. Our workover costs for the nine months ended September 30, 2011 decreased to $5.8 million, or $1.96 per Boe, from $6.1 million in the comparable period of 2010, or $2.11 per Boe. The decrease in workover costs from the comparable period in 2010 was primarily a result of changes in projects needed to manage our wells and maintain efficient production levels.

Depreciation, depletion and amortization. Depreciation, depletion and amortization for the nine months ended September 30, 2011 decreased to $44.5 million from $59.3 million in the comparable period in 2010. The decrease in depreciation, depletion and amortization was primarily due to a decrease in the depletion rate based on the calculation which uses higher future gross revenues on reserves existing in 2011 compared to 2010.

General and administrative expenses. General and administrative expense increased to $13.2 million during the nine months ended September 30, 2011, from $10.3 million in the comparable period in 2010. The increase in general and administrative expense is primarily due to higher salaries and office rent from the establishment of a Denver office location, increased consultant compensation for the use of more specialized consultants on technical projects and additional accounting and legal fees incurred for regulatory compliance matters pursuant to the registration of the Notes.

Bad debt expense. Bad debt expense increased to $0.8 million during the nine months ended September 30, 2011, from zero in the comparable period in 2010. This increase is due to an analysis indicating that amounts owed to the Company by one customer are anticipated to be uncollectible.

Interest expense. Net interest expense increased to $11.8 million for the nine months ended September 30, 2011, from $3.3 million for the nine months ended September 30, 2010 due to higher outstanding debt balances and interest rates associated with the issuance of the Notes in late September 2010 and mid-July 2011. Debt balances averaged $184.4 million during the nine months ended September 30, 2011 and $107.8 million during the nine months ended September 30, 2010. Interest rates averaged 12.50% during the nine months ended September 30, 2011 and 3.68% during the nine months ended September 30, 2010. The increase in interest rates is due to the Company issuing the Notes and using a portion of the proceeds from the Original Notes offering to repay all of the outstanding indebtedness under the revolving credit facility.

 

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Loss from equity investment. During the nine months ended September 30, 2011, the Company recorded an OTTI charge of $2.0 million on our Attune Australia investment.

Income tax provision. For the nine months ended September 30, 2011, the Company recorded income tax expense of $17.5 million as compared to income tax expense of $19.2 million for the nine months ended September 30, 2010. Income tax expense recognized was based on an effective tax rate calculation of 36.6% at September 30, 2011 and 2010. Our effective tax rate differs from the statutory federal income tax rate primarily because of state and local income taxes, domestic production activities deductions, and percentage of depletion in excess of basis.

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 $138 million on capital expenditures during the first nine months of 2011. We anticipate spending an additional $96 million on capital expenditures during the remainder of 2011. 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 2011 capital expenditure budget is approximately $234 million, of which approximately $138 million was expended in the first nine months of 2011 including $14 million of prepaid drilling and exploration in Oklahoma, which is recorded in Other assets. The remaining capital budget of $96 million consists of:

 

   

$35 million for geological and geophysical costs, including $27 million leasing in two new prospect areas in Colorado and Texas;

 

   

$18 million for Louisiana state water drilling and development prospects;

 

   

$1 million for onshore drilling and development prospects in Alabama, Mississippi and Louisiana;

 

   

$6 million for onshore drilling and development prospects in Texas;

 

   

$6 million for onshore drilling and development prospects in Oklahoma and California;

 

   

$27 million for final completion operations and platform and infrastructure upgrades for all project areas; and

 

   

$3 million for plugging and abandonment costs primarily for offshore properties.

While we have budgeted $96 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 2011 capital budget has been funded from debt financing and our cash flows from operations. We believe the proceeds from the Notes and cash flows from operations should be sufficient to fund the remainder of our 2011 capital expenditure budget.

 

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During October 2011, the operator of the New Mexico wells we have an interest in informed the Company that they have decided to plug and abandon the five wells which were previously being tested. Our share of the operator’s budget to plug and abandon these wells is approximately $0.5 million, which is included in the budget discussed above.

As of September 30, 2011 we had no indebtedness outstanding under our revolving credit facility (the “Amended 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 for cash 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.

The table below discloses the net cash provided by (used in) operating activities, investing activities, and financing activities for the nine months ended September 30, 2011 and 2010:

 

                 Nine Months Ended  September 30                  
    

2011

    

2010

 

In thousands

     

Net cash provided by operating activities

               $ 113,994       $ 88,506       

Net cash used in investing activities

     (155,797)         (43,009)       

Net cash provided by financing activities

     47,785         31,493       
  

 

 

 

Net increase in cash and cash equivalents

               $     5,982       $     76,990       
  

 

 

 

Cash flows provided by operating activities

Operating activities provided cash totaling $114.0 million during the nine months ended September 30, 2011 as compared to cash provided by operating activities of $88.5 million during the nine months ended September 30, 2010. The increase in operating cash flows during the nine months ended September 30, 2011 was principally attributable to higher accounts payable balances during the period and increased revenues payable to our partners offset by the payment of interest on our Notes at September 30, 2011.

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 $155.8 million during the nine months ended September 30, 2011 as compared to cash used in investing activities of $43.0 million during the comparable period in 2010. Cash used in investing activities during the nine months ended September 30, 2011 increased as compared to the same period of 2010 primarily because of increased drilling in Louisiana state waters, the implementation of an active drilling program for its prospects onshore Texas and a $14.0 million prepayment for Oklahoma drilling expenses.

 

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Our capital expenditures for drilling, development and acquisition costs for the nine months ended September 30, 2011 and 2010 are summarized in the following table (in thousands):

 

                 Nine Months Ended  September 30              
    

2011

    

2010

 

Project Area

     

Federal

               $ 4,249       $ 9,166     

Shallow State Waters

     46,390         7,367     

Onshore Texas, Louisiana and Mississippi

     60,107         16,719     

Oklahoma and Mid-Continent

     27,179         8,854     
  

 

 

 

Total

               $             137,925       $             42,106     
  

 

 

 

Cash flows provided by financing activities

Financing activities provided cash totaling $47.8 million during the nine months ended September 30, 2011 as compared to cash provided by financing activities of $31.5 million during the comparable period in 2010. Cash flows provided by financing activities during the first nine months of 2011 consisted primarily of $51.3 million in proceeds from the issuance of the Additional Notes and $8.0 million in proceeds from insurance premium financing offset by payments of $10.0 million on borrowings and shareholder dividends. Cash flows provided by financing activities during the first nine months of 2010 were mainly comprised of $148.6 million in proceeds from the issuance of the Original Notes and $8.9 million in proceeds from insurance premium financing offset by payments of $119.5 million on the Company’s revolving credit facility, insurance premium note payable and shareholder dividends.

Off-Balance Sheet Arrangements

As of September 30, 2011 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 September 30, 2011, on a BOE basis, commodity derivative instruments were in place covering approximately 36% of our projected oil and natural gas sales through 2011, approximately 27% of our projected oil and natural gas sales for 2012, approximately 26% of our projected oil and natural gas sales for 2013 and approximately 8% of our projected oil and natural gas sales for 2014. Approximately 35% of the Company’s remaining 2011 gas production, approximately 23% of the Company’s 2012 gas production, approximately 27% of the Company’s 2013 gas production, approximately 39% of the Company’s remaining 2011 oil production, approximately 37% of the Company’s 2012 oil production, approximately 24% of the Company’s 2013 oil production and approximately 24% 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

 

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Activities.” Future oil and gas sales prices on other production will fluctuate according to market conditions.

As of September 30, 2011, 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      Floor    
  

 

 

    

 

 

 

Period

           

2011(1)

     39,000                       $ 86.21           8,333       $                 91.80   

2012

     42,667                       $             81.84                 $ –     

2013

     18,225                       $             81.79                 $ –     

2014 (2)

     17,433                       $             85.55                 $ –     

(1)  Average hedged volume is calculated for the remainder of the 2011 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.

As of September 30, 2011, the Company had entered into the following natural gas derivative instruments:

 

     NYMEX Contract Price  
  

 

 

 
     Total Futures      Total Options  
  

 

 

    

 

 

 
       Volume in Mbtu/Mo      Weighted Average Fixed Price          Volume in Mbtu/Mo      Estimated  Price(2)    
  

 

 

    

 

 

 

Period

           

2011(1)

     537,333                       $ 5.47           101,667       $             4.94   

2012

     307,833                       $ 5.23           152,500       $ 5.01   

2013

     152,083                       $             5.40           152,500       $ 5.46   

(1)  Average hedged volume is calculated for the remainder of the 2011 year.

(2)  For the period remaining in 2011 and for 2012 and 2013, the Company has entered into protective spreads where the price to be realized by the Company is dependent on the NYMEX contract closing price. The Company has estimated the price it will receive based on the closing NYMEX prices as of September 30, 2011.

Each of these transactions were designated as cash flow hedges. 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.

 

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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 initially issued notes, although they bear a different CUSIP number than the Original Notes until they are no longer restricted securities under the Securities Act of 1933. On October 18, 2011, the Company initiated an exchange offer to register all of the Additional Notes that expires on November 18, 2011, unless extended by the Company.

As of September 30, 2011, 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 September 30, 2011.

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

Effective as of September 24, 2010, we entered into an amended revolving credit facility (the “Amended Revolving Credit Facility”). Century Exploration New Orleans, LLC and Century Exploration Houston, LLC are the borrowers under our Amended Revolving Credit Facility and the Company, Century Exploration Resources, LLC, Sita Energy LLC and Windstar Energy, LLC guarantee their obligations thereunder. Our Amended Revolving Credit Facility provides for a revolving line of credit in an aggregate principal amount of up to $62.5 million. Loans under the Amended Revolving Credit Facility are denominated in U.S. dollars. Union Bank, N.A. acts as administrative agent and collateral agent for the revolving credit facilities. The Amended Revolving Credit Facility has a two-year maturity.

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 September 30, 2011, 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).

 

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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 S-4.

Recently Issued Accounting Pronouncements

ASU Number 2011-5 was issued in June 2011, amending Topic 220 — Comprehensive Income. 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 will change our existing presentation, but will not impact the components of other comprehensive income. The ASU is effective for fiscal periods beginning after December 15, 2011.

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 nine months ended September 30, 2011, our annual revenue would increase or decrease by approximately $10.4 million for each $10.00 per barrel change in crude oil prices and $17.4 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.

 

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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 ($4.9 million at September 30, 2011) and the sale of our crude oil and natural gas production, which we market to energy marketing companies, refineries and affiliates ($32.2 million in receivables at September 30, 2011). 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.

Interest Rate Risk

Our exposure to changes in interest rates relates primarily to long-term debt obligations. Historically, we were exposed to changes in interest rates as a result of our revolving credit facility and this exposure will remain under our Amended Revolving Credit Facility. No debt was outstanding under the Amended Revolving Credit Facility at September 30, 2011. The majority of our long-term debt obligations consist of the outstanding senior notes, which have a fixed interest rate; therefore, we are not exposed to interest rate risk through these notes and our overall interest rate risk exposure is low. For additional information regarding our Amended Revolving Credit Facility, see Part I, Item 2 “Management’s Discussion and Analysis Financial Condition and Results of Operations — Amended Revolving Credit Facility.” We do not believe our interest rate exposure warrants entry into interest rate hedges and have, therefore, not hedged our interest rate exposure.

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 upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2011 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 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

 

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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 for the period in which the resolution occurs.

Item 1A.  Risk Factors

The following risk factors should be read in conjunction with our risk factors described in the Form S-4. You should carefully consider each of the risks described below and contained in our Form S-4, together with all of the other information contained in the Form S-4 and this report, including our unaudited condensed consolidated financial statements and related notes. 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.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could make it more difficult or costly for us to perform fracturing of producing formations and could have an adverse effect on our ability to produce oil and gas from new wells.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel under the Safe Drinking Water Act’s Underground Injection Control Program and has begun the process of drafting guidance documents on regulating requirements for companies that plan to conduct hydraulic fracturing using diesel. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a number of federal agencies are analyzing a number of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing activities, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy and the U.S. Government Accountability Office are studying different aspects of how hydraulic fracturing might adversely affect the environment, and the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands. A committee of the United States House of Representatives also has conducted an investigation of hydraulic fracturing practices. Additionally, certain members of the Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the U.S. Securities and Exchange Commission to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the Safe Drinking Water Act or under newly established legislation. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.

In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure, or well construction requirements on hydraulic fracturing operations . On June 17, 2011, Texas signed into law a bill that requires, subject to certain trade secret protections, disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas and the public. The Louisiana Department of Natural Resources adopted a similar disclosure regulation in October 2011. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

 

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

On July 28, 2011, the U.S. Environmental Protection Agency (“EPA”) issued proposed rules that would subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs. The EPA proposed rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion (REC) techniques developed in EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (MACT) standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business.

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

   

November 14, 2011

 

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)).

  4.1

  

Indenture, dated as of September 24, 2010, among RAAM Global Energy Company, the several guarantors named therein, and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (incorporated by reference from Exhibit 4.1 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).

  4.1.1

  

First Supplemental Indenture, dated as of July 15, 2011, to the Indenture dated September 24, 201, among RAAM Global Energy Company, the several guarantors named therein, and The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (incorporated by reference from Exhibit 4.1 to the Form 8-K filed on July 19, 2011 (File No. 333-172897)).

  4.2

  

Registration Rights Agreement dated as of July 15, 2011, among RAAM Global Energy Company, the Guarantor parties named therein and the Initial Purchasers named therein (incorporated by reference from Exhibit 4.3 to the current report on Form 8-K filed on July 19, 2011 (File No. 333-172897)).

  4.3

  

Intercreditor Agreement, dated as of September 24, 2010, by and among Union Bank, N.A., as administrative agent for the first lien creditors named therein, the Bank of New York Mellon Trust Company, N.A., as indenture trustee for the second lien creditors named therein, Century Exploration New Orleans, Inc., Century Exploration Houston, Inc and RAAM Global Energy Company (incorporated by reference from Exhibit 4.3 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).

  4.4

  

Security Agreement, dated September 24, 2010, by RAAM Global Energy Company and the several guarantors name therein in favor of Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent (incorporated by reference from Exhibit 4.4 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).

10.1

  

Form of Stock Purchase Agreement, effective August 24, 2011, between the Sellers defined therein and RAAM Global Energy Company (incorporated by reference from Exhibit 10.1 to the current report of Form 8-K filed on August 29, 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 September 30, 2011 and December 31, 2010; (ii) our Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and 2010; (iii) our Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010; and (v) the notes to our 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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