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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, 2012

 

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

For the transition period from                      to                     .

Commission File No. 333-172897

RAAM Global Energy Company

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   20-0412973

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

1537 Bull Lea Rd., Suite 200  
Lexington, Kentucky   40511
(Address of principal executive offices)   (Zip Code)

(859) 253-1300

(Registrant’s telephone number, including area code)

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨

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

 

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 12, 2012, there were 62,500 shares of common stock, $0.01 par value, outstanding.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

     Page  

Cautionary Note Regarding Forward-looking Statements

  

Part I. Financial Information

  

Item 1. Financial Statements

  

Condensed Consolidated Balance Sheets

     5   

Condensed Consolidated Statements of Operations

     7   

Condensed Consolidated Statements of Comprehensive Income

     8   

Condensed Consolidated Statements of Cash Flows

     9   

Notes to Unaudited Condensed Consolidated Financial Statements

     10   

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

     20   

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     32   

Item 4. Controls and Procedures

     33   

Part II. Other Information

  

Item 1. Legal Proceedings

     33   

Item 1A. Risk Factors

     33   

Item 6. Exhibits

     34   

SIGNATURES

     35   

Exhibit Index

     36   

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). 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 “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “plan,” “foresee,” “should,” “would,” “could” 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 and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. 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.

Forward-looking statements involve known and unknown risks, uncertainties and other factors (some of which are beyond our control) that may cause our actual results, performance or achievements to be materially different from those 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;

 

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geological concentration of our reserves;

 

   

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 Isaac, Katrina, Rita, Gustav and Ike and the Deepwater Horizon explosion; and

 

   

worldwide political and economic conditions.

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

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

All subsequent written and oral forward-looking statements attributable to us 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. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. 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,     December 31,  
     2012     2011  

Assets

    

Current assets:

    

Cash and cash equivalents

   $ 48,664     $ 51,743  

Accounts receivable, net of $289 and $1,005 provision for bad debts in 2012 and 2011, respectively

     3,179       5,642  

Revenues receivable

     31,734       31,532  

Income taxes receivable

     2,069       2,118  

Deferred tax asset—current portion

     5,537       —     

Commodity derivatives—current portion

     167       12,674  

Prepaid assets

     5,004       4,945  

Other current assets

     5,648       3,919  
  

 

 

   

 

 

 

Total current assets

     102,002       112,573  

Oil and gas properties (full-cost method):

    

Properties being amortized

     1,380,713       1,203,272  

Properties not subject to amortization

     84,664       111,621  

Less accumulated depreciation, depletion, and amortization

     (779,969     (720,062
  

 

 

   

 

 

 

Net oil and gas properties

     685,408       594,831  

Other assets:

    

Other capitalized assets, net

     6,869       7,183  

Commodity derivatives

     1,104       3,191  

Other

     3,772       5,698  
  

 

 

   

 

 

 

Total other assets

     11,745       16,072  
  

 

 

   

 

 

 

Total assets

   $ 799,155     $ 723,476  
  

 

 

   

 

 

 

See accompanying notes to the unaudited 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,
2012
    December 31,
2011
 

Liabilities and shareholders’ equity

    

Current liabilities:

    

Accounts payable and accrued liabilities

   $ 24,889     $ 52,969  

Revenues payable

     24,745       29,319  

Interest payable—senior secured notes

     —          6,250  

Current taxes payable

     —          399  

Advances from joint interest partners

     294       1,019  

Commodity derivatives—current portion

     3,340       —     

Asset retirement obligations—current portion

     10,155       1,778  

Debt—current portion

     3,797       1,929  

Deferred income taxes—current portion

     —          3,109  
  

 

 

   

 

 

 

Total current liabilities

     67,220       96,772  

Other liabilities:

    

Commodity derivatives

     4,086       4,244  

Asset retirement obligations

     31,645       25,010  

Debt

     52,619       2,733  

Senior secured notes

     199,981       199,972  

Deferred income taxes

     146,169       105,095  

Other long-term liabilities

     395       467  
  

 

 

   

 

 

 

Total other liabilities

     434,895       337,521  
  

 

 

   

 

 

 

Total liabilities

     502,115       434,293  

Commitments and contingencies (see Note 10)

    

Shareholders’ equity and noncontrolling interest:

    

Common stock, $0.01 par value, 380,000 shares authorized,

    

62,500 outstanding in 2012 and 2011, respectively

     62,478       62,478  

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

     (5,736     (5,736

Retained earnings

     232,306       224,513  

Accumulated other comprehensive income, net of taxes

     7,136       7,928  
  

 

 

   

 

 

 

Total shareholders’ equity attributable to RAAM Global

     296,184       289,183  

Noncontrolling interest

     856       —     
  

 

 

   

 

 

 

Total shareholders’ equity

     297,040       289,183  

Total liabilities and shareholders’ equity

   $ 799,155     $ 723,476  
  

 

 

   

 

 

 

See accompanying notes to the unaudited 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  
     2012     2011     2012     2011  

Revenues:

        

Gas sales

   $ 18,405      $ 26,770      $ 62,872      $ 76,194   

Oil sales

     28,654        27,284        80,409        74,190   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     47,059        54,054        143,281        150,384   

Costs and expenses:

        

Production and delivery costs

     8,060        8,156        26,188        24,508   

Workover costs

     727        4,568        2,167        5,786   

Depreciation, depletion and amortization expenses

     20,736        13,387        60,911        44,450   

General and administrative expenses

     3,602        4,815        13,897        13,929   

Derivative expense

     523        822       2,727        283  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expense

     33,648        31,748        105,890        88,956   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income from operations

     13,411        22,306        37,391        61,428   

Other income (expenses):

        

Interest expense, net

     (6,210     (5,437     (14,156     (11,785

Loss from equity investment

     —          (2,044     —          (2,044

Other, net

     9        (30     226        151   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expenses)

     (6,201     (7,511     (13,930     (13,678
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before taxes

     7,210        14,795        23,461        47,750   

Income tax provision

     4,396        5,480        10,125        17,490   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income including noncontrolling interest

   $ 2,814      $ 9,315      $ 13,336      $ 30,260   
  

 

 

   

 

 

   

 

 

   

 

 

 

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

     653        (3     856        1,476   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to RAAM Global

   $ 2,161      $ 9,318      $ 12,480      $ 28,784   
  

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to the unaudited condensed consolidated financial statements.

 

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RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

(Unaudited)

 

     Three Months Ended September 30     Nine Months Ended September 30  
     2012     2011     2012     2011  

Net income including noncontrolling interest

   $ 2,814      $ 9,315      $ 13,336      $ 30,260   

Changes in fair value of hedges

     (13,121     9,469        (1,264     2,316   

Income tax expense related to components of other comprehensive income

     4,903        (3,666     472        (897
  

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income (loss)

   $ (5,404   $ 15,118      $ 12,544      $ 31,679   

Less: Comprehensive (income) loss attributable to noncontrolling interest

     (653     3       (856     (1,476
  

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income (loss) attributable to RAAM Global

   $ (6,057   $ 15,121      $ 11,688      $ 30,203   
  

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to the unaudited 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  
     2012     2011  

Operating activities

    

Net income including noncontrolling interest

   $ 13,336     $ 30,260  

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

    

Depreciation, depletion and amortization expenses

     62,292       45,841  

Deferred income taxes

     32,428       15,538  

Loss on disposal of inventory and properties

     —          20  

Loss on equity method investment

     —          2,044  

Changes in assets and liabilities:

    

Accounts and revenues receivable

     2,262       7,033  

Income tax receivables

     49       (1,188

Prepaids and other current assets

     72       (1,275

Change in derivatives, net

     16,983       (614

Accounts payable and accrued liabilities

     (13,607     10,212  

Revenues payable

     (4,574     12,470  

Interest payable on Senior Notes

     (6,250     (5,048

Current taxes payable

     (398     1,293  

Other long-term liabilities

     (72     —     
  

 

 

   

 

 

 

Net cash provided by operating activities

     102,521       116,586  

Investing activities

    

Change in advances from joint interest partners

     (725     1,003  

Payment of prepaid drilling expenses

     —          (14,000

Additions to oil and gas properties and equipment

     (166,266     (123,925

Purchase of noncontrolling interest

     —          (21,000

Proceeds from net sales of oil and gas properties

     16,185       2,125  
  

 

 

   

 

 

 

Net cash used in investing activities

     (150,806     (155,797

Financing activities

    

Proceeds from revolving credit facility

     50,000       —     

Proceeds from issuance of 12.5% Senior Notes due 2015

     —          51,250  

Payments on debt

     (106     (89

Payments of deferred bond costs

     —          (1,468

Payment of dividends

     (4,688     (4,500
  

 

 

   

 

 

 

Net cash provided by financing activities

     45,206       45,193  
  

 

 

   

 

 

 

(Decrease) increase in cash and cash equivalents

     (3,079     5,982  

Cash and cash equivalents, beginning of period

     51,743       81,032  
  

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 48,664     $ 87,014  
  

 

 

   

 

 

 

See accompanying notes to the unaudited condensed consolidated financial statements.

 

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RAAM GLOBAL ENERGY COMPANY

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Nature of Business

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

2. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

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

The Condensed Consolidated Balance Sheets as of December 31, 2011 was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”). Certain notes and other information have been condensed or omitted from the interim financial statements presented in this quarterly report. Therefore, these financial statements and notes should be read in conjunction with the Company’s audited annual consolidated financial statements and the notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2011.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates. The Company’s most significant financial estimates are based on remaining proved oil and gas reserves.

Oil and Gas Properties

The Company uses the full-cost method of accounting for exploration and development costs. Accordingly, all costs associated with acquisition, exploration and development of oil and gas reserves, including interest related to significant properties being evaluated and directly related overhead costs, are capitalized. Capitalized overhead costs amounted to $1.1 million and $1.2 million for the three months ended September 30, 2012 and 2011, respectively, and $3.4 million and $3.7 million for the nine months ended September 30, 2012 and 2011, respectively. The Company capitalized interest of $1.0 million and $1.1 million during the three months ended September 30, 2012 and 2011, respectively, related to significant active properties not subject to amortization. The Company capitalized interest of $6.7 million and $5.1 million during the nine months ended September 30, 2012 and 2011, respectively, related to significant active properties not subject to amortization.

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

 

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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.

Unevaluated properties and associated costs not currently being amortized and included in oil and gas properties were $84.7 million and $111.6 million at September 30, 2012 and December 31, 2011, respectively. The Company believes that the unevaluated properties at September 30, 2012 will be substantially evaluated during the remainder of 2012, 2013 and 2014, and the costs will begin to be amortized at that time.

Each quarter, we review the carrying value of our capitalized oil and gas properties under the full cost accounting guidance of the SEC. This review is referred to as a “ceiling test.” Capitalized costs, less accumulated amortization and related deferred income taxes, shall not exceed an amount equal to the sum of the estimated present value of future net cash flows from proved reserves discounted at 10%, less estimated future expenditures to be incurred in developing and producing the 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. To calculate estimated future net revenues, current prices are calculated using the average of the first-day-of-the-month price for the trailing 12-month period. These prices are used except where different prices are fixed and determinable through contractual arrangements, including the effects of derivatives qualifying as cash flow hedges.

At September 30, 2012, the Company’s ceiling test computation did not result in a write-down and was based on twelve-month average prices of $91.48 per barrel of oil and $2.83 per MMBtu of natural gas. Cash flow hedges existing at September 30, 2012, which relate to future production periods, decreased the full cost ceiling by approximately $4.6 million. At December 31, 2011, the Company’s ceiling test computation did not result in a write-down and was based on twelve-month average prices of $92.71 per barrel of oil and $4.12 per MMBtu of natural gas. Cash flow hedges existing at December 31, 2011, which relate to future production periods, increased the full cost ceiling by approximately $11.3 million.

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 third quarter of 2012, the Company sold approximately 15,000 net acres in oil, gas and/or mineral leases and a total of approximately 56,000 net acres, which includes options in oil, gas and/or mineral leases, located in Texas and Louisiana and a well and related equipment located in Louisiana, along with all of our contracts and agreements related to this property to an unrelated third party. The sales price was approximately $14.0 million and was recorded as a reduction to net oil and gas properties on the accompanying condensed consolidated balance sheets, with no income statement impact because the sale does not significantly alter the relationship between capitalized costs and proved reserves.

During the second quarter of 2012, the Company sold a wellbore and production facility in Louisiana state waters to an unrelated third party. The sales price was approximately $2.0 million and was recorded as a reduction to our net oil and gas properties on the accompanying condensed consolidated balance sheets, with no income statement impact because the sale does not significantly alter the relationship between capitalized costs and proved reserves.

During the second quarter of 2011, the Company sold approximately 16,000 acres onshore Mississippi to an unrelated third party oil and gas company. The sales price was approximately $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 sheets, with no income statement impact because the sale does not significantly alter the relationship between capitalized costs and proved reserves.

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

 

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Hedging Activities

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

The Company follows the provisions of the Financial Accounting Standards Board (“FASB”) guidance related to accounting for derivative instruments and hedging activities. This guidance requires all derivatives to be reported as assets or liabilities at their fair values, and the balance sheet caption Commodity Derivatives is being used in the accompanying condensed consolidated balance sheets for this purpose. This guidance also imposes additional documentation requirements in order for derivatives to be accounted for as hedges of future risks. The Company designated all new commodity derivative swap instruments entered into in 2012 and 2011 as hedges for accounting purposes, so the related unrealized changes in their fair values are reported net of tax in the accompanying condensed consolidated balance sheets as a component of Accumulated 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. The Company did not designate all new option contracts (puts and calls) entered into in 2012 and 2011 as hedges for accounting purposes, so the related unrealized changes in their fair values are recorded in current-period earnings in the accompanying condensed consolidated statements of operations in Derivative expense. Actual monthly settlements are recorded as hedging (losses) gains in Gas sales and Oil sales in the accompanying condensed consolidated statements of operations. For more information on the Company’s hedging activities see Note 5.

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 Company uses an indicators approach similar to the approach used to identify impairment indicators under the guidance for impairment or disposal of long-lived assets to determine when ARO estimates should be reassessed. The Company evaluates whether there are any indicators that suggest that the expected cash flows underlying the ARO liability have changed materially.

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, 2012 and December 31, 2011 was $34.5 million and $21.5 million, respectively. Accretion of the discounted asset retirement obligations is recognized as an increase in the carrying amount of the liability and as an expense in Depreciation, depletion and amortization expenses on the accompanying condensed consolidated statements of operations.

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

 

In thousands       

Balance of ARO as of January 1, 2012

   $ 26,788  

Accretion expense

     538   

Additions

     2,279   

Settlement of ARO

     (827

Changes in ARO estimate

     13,022   
  

 

 

 

Balance of ARO as of September 30, 2012

   $ 41,800  
  

 

 

 

 

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A portion of the increase in the ARO estimate during the third quarter of 2012 is related to a transaction with a former partner in which we obtained their interest in a property, along with a cash settlement from them for their portion of the ARO. Their portion of the ARO on this property is now included in our ARO estimate. In connection with this agreement, we obtained updated third party estimates of the related AROs. Based on new government regulations as well as increased costs to perform plugging and abandonment work in the Gulf of Mexico, the ARO has increased substantially. As a result, we have re-evaluated our AROs recorded for properties in this area. Additionally, this quarter Hurricane Isaac impacted one of our wells causing changes in the ARO estimate for this well.

Reclassifications

Certain prior year amounts have been reclassified in the accompanying consolidated financial statements to conform with the 2012 presentation. Such reclassifications are not material to the accompanying consolidated financial statements and had no impact on previously reported net income.

Operating Segments

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

New Accounting Pronouncements

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

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

3. Fair Value Measurements

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

 

   

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.

 

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

 

     Fair Value Measurements Using Significant
Other Observable Inputs (Level 2)
 
Description    September 30, 2012     December 31, 2011  
In thousands             

Assets:

    

Fair value of commodity derivatives—current assets

   $ 167     $ 12,674  

Fair value of commodity derivatives—long-term assets

     1,104       3,191  
  

 

 

   

 

 

 

Total Assets

   $ 1,271     $ 15,865  
  

 

 

   

 

 

 

Liabilities:

    

Fair value of commodity derivatives—current liabilities

   $ (3,340   $ —     

Fair value of commodity derivatives—long-term liabilities

     (4,086     (4,244
  

 

 

   

 

 

 

Total Liabilities

   $ (7,426   $ (4,244
  

 

 

   

 

 

 

During September 2010 and July 2011, the Company issued Senior Secured Notes. At September 30, 2012, the fair value of the Notes was estimated to be $206.0 million, based on the prices the bonds have recently been quoted at in the market, which represent Level 2 inputs. As of September 30, 2012, a total of $200.0 million notional amount of the Notes was outstanding. The carrying amount of the Notes was $200.0 million as of September 30, 2012. See Note 6, Debt, for further information.

The carrying value of Cash and cash equivalents, Accounts receivable, Revenues receivable, Accounts payable, and Revenues payable approximate fair value because of the short-term maturity of those instruments. Borrowings under the Amended Revolving Credit Facility (as defined in Note 6) are at variable interest rates and accordingly their carrying amounts approximate fair value.

4. Accounts and Revenues Receivable

Accounts and revenues receivable at September 30, 2012 and December 31, 2011 were $34.9 million and $37.2 million, respectively, all of which were due from companies in the oil and gas industry. Of the revenues receivable, $25.7 million and $27.0 million were due from five companies at September 30, 2012 and December 31, 2011, respectively.

Since all of RAAM Global’s accounts receivable from purchasers and joint interest owners at September 30, 2012 and December 31, 2011 resulted from sales of crude oil, condensate, natural gas and/or joint interest billings to third-party companies in the oil and gas industry, this concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly

 

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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, 2012 and December 31, 2011. 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 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 sales.

All of the Company’s commodity derivative transactions are settled based on reported settlement prices on the New York Mercantile Exchange (“NYMEX”). The estimated fair value of these transactions is based on various factors that include closing exchange prices on the NYMEX, over-the-counter quotations, volatility and the time value of options. The calculation of the fair value of collars and floors utilizes the Black-Scholes option-pricing model. Since the swap transactions were designated as hedges, the Company records the changes in fair value of these transactions as Accumulated Other Comprehensive Income in the accompanying condensed consolidated balance sheets with the ineffective portion of the change in fair value reported as Derivative expense in the accompanying condensed consolidated statements of operations. The Company did not designate new option contracts (puts and calls) entered into in 2012 and 2011 as hedges for accounting purposes, so the related unrealized changes in fair values of these option contracts are recorded in current-period earnings in the accompanying condensed consolidated statement of operations in Derivative expense. At September 30, 2012, the Company had approximately $0.6 million of options not designated as hedges for accounting purposes, which are included in Commodity derivatives – current portion in the current liabilities section of the condensed consolidated balance sheets and $1.0 million included in Commodity derivatives in the other liabilities section of the condensed consolidated balance sheets. At December 31, 2011, the Company had approximately $1.9 million of options not designated as hedges for accounting purposes included in Commodity derivatives – current portion in the current assets section of the condensed consolidated balance sheets and $1.6 million included in Commodity derivatives in the other liabilities section of the condensed consolidated balance sheets. 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, 2012 and 2011, the Company realized a net increase in oil and gas revenues related to hedging transactions of $5.3 million and $1.4 million, respectively. For the nine months ended September 30, 2012 and 2011, the Company realized a net increase in oil and gas revenues related to hedging transactions of $18.0 million and $8.1 million, respectively. The Company anticipates the amount of accumulated other comprehensive income (loss) related to hedge transactions that will settle during the next twelve months will be approximately $(2.0) million, net of tax effects.

The increase in oil and gas revenues related to hedging transactions for the three and nine months ended September 30, 2012 includes the monetization of gas hedges in February 2012 resulting in additional revenues of $4.0 million and $9.5 million, respectively, for forecasted transactions that would have settled during the periods. At September 30, 2012, $13.8 million of monetized hedges remain in accumulated other comprehensive income, net of tax effects

 

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and will be recognized in revenues in the period when the contract would have settled if the hedges had not been monetized.

Hedge ineffectiveness for the derivative swap instruments was $(1.1) million and $(0.8) million for the three months ended September 30, 2012 and 2011, respectively. Hedge ineffectiveness for the derivative swap instruments was $(0.8) million and $(0.3) million for the nine months ended September 30, 2012 and 2011, respectively. The options had an unrealized change in fair value during the three months ended September 30, 2012 of $0.6 million. The options had an unrealized change in fair value during the nine months ended September 30, 2012 of $(1.9) million. All amounts have been recorded in Derivative expense in the condensed consolidated statements of operations.

As of September 30, 2012, the Company held the commodity derivative instruments shown below related to the forecasted sale of its U.S. Gulf Coast natural gas production for 2012, 2013, 2014 and 2015:

 

Remaining Contract Term

   Contract
Type
     Volume in
MMBtus/
Month
     NYMEX
Strike
Price
 

October 2012—December 2012

     Swap         122,667       $ 3.05  

October 2012—December 2012

     Swap         470,000       $ 3.00  

October 2012—December 2012

     Swap         153,333       $ 3.67  

October 2012—December 2012

     Swap         211,700       $ 2.94  

January 2013—September 2013

     Swap         90,556       $ 3.70  

January 2013—December 2013

     Swap         152,083       $ 3.67  

January 2013—December 2013

     Swap         302,625       $ 3.81  

January 2013—December 2013

     Swap         122,325       $ 3.79  

January 2014—June 2014

     Swap         150,833       $ 4.09  

January 2014—December 2014

     Swap         152,083       $ 3.67  

January 2014—December 2014

     Swap         121,083       $ 4.15  

January 2014—December 2014

     Swap         79,850       $ 4.00  

July 2014—December 2014

     Swap         30,667       $ 4.00  

January 2015—December 2015

     Swap         167,042       $ 4.94  

January 2015—December 2015

     Swap         85,433       $ 4.35  

 

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

 

Remaining Contract Term

   Contract
Type
   Volume in
BBls/
Month
     NYMEX
Strike
Price
 

October 2012—December 2012

   Call—Sell      3,680       $ 110.00  

October 2012—December 2012

   Swap      12,533       $ 100.02  

October 2012—December 2012

   Swap      6,133       $ 100.30  

October 2012—December 2012

   Put—Sell      59,800       $ 75.00  

October 2012—December 2012

   Swap      39,867       $ 84.00  

October 2012—December 2012

   Swap      23,067       $ 94.69  

January 2013—June 2013

   Swap      21,117       $ 84.70  

January 2013—December 2013

   Call—Sell      13,292       $ 125.00  

January 2013—December 2013

   Swap      8,833       $ 95.72  

January 2013—December 2013

   Put—Sell      21,292       $ 70.00  

January 2013—December 2013

   Put—Buy      13,292       $ 70.00  

January 2013—December 2013

   Call—Sell      13,292       $ 109.10  

January 2013—December 2013

   Call—Buy      13,292       $ 125.00  

January 2013—December 2013

   Swap      11,436       $ 95.35  

July 2013—December 2013

   Swap      15,333       $ 85.50  

January 2014—June 2014

   Swap      24,133       $ 85.40  

January 2014—September 2014

   Call—Sell      21,233       $ 95.00  

January 2014—September 2014

   Call—Buy      21,233       $ 85.50  

January 2014—September 2014

   Put—Buy      21,233       $ 63.60   

July 2014—September 2014

   Swap      21,467       $ 85.90   

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

6. Debt

2015 Senior Secured Notes

On September 24, 2010, the Company 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 Amended Revolving Credit Facility (as defined below) 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

 

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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. On November 18, 2011, the Company closed an exchange offer registering all of the Additional Notes.

As of September 30, 2012, a total of $200.0 million notional amount of the Notes were outstanding. The carrying amount of the Notes was $200.0 million as of September 30, 2012. At September 30, 2012, the fair value of the Notes was estimated to be $206.0 million, based on the prices the Notes have recently been quoted at in the market.

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

Each of RAAM Global’s 100% owned subsidiaries are guarantors of the Notes. The parent company has no independent assets or operations, as defined in SEC Regulation S-X, the guarantees are joint and several, and are full and unconditional (subject to certain customary automatic subsidiary release provisions).

Amended Revolving Credit Facility

The Company’s Third Amended and Restated Credit Agreement, as amended (the “Amended Revolving Credit Facility”) has a maturity date of July 1, 2015. The borrowing base remains $62.5 million of which $50.0 million was drawn at September 30, 2012 and zero was drawn at December 31, 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. The Company was in compliance with these debt covenants at September 30, 2012.

Promissory Note

The Company has a promissory note with GE Commercial Finance Business Property Corporation (“GECF”) related to the construction of the Houston office building. The balance was $2.8 million at September 30, 2012 and $2.9 million at December 31, 2011. The GECF note requires monthly installments of principal and interest in the amount of approximately $27,000 until September 1, 2025. There are no covenant requirements under this promissory note.

Finance Agreement

During May 2012, the Company entered into an agreement to finance the premiums for its annual insurance policies with Premium Assignment Corporation. At September 30, 2012, $3.7 million was outstanding under this agreement. During the third quarter of 2012, an adjustment was made to this agreement resulting in a slight decrease in the remaining monthly payments. The finance agreement requires monthly installments of principal and interest in the amount of approximately $0.6 million until April 1, 2013. There are no covenant requirements under this agreement.

 

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7. Income Taxes

The Income tax provision for the three months ended September 30, 2012 was $4.4 million, or an effective tax rate of 61.0%, compared to $5.5 million, or an effective tax rate of 37.0%, for the three months ended September 30, 2011. The Income tax provision for the nine months ended September 30, 2012 was $10.1 million or an effective tax rate of 43.2%, compared to $17.5 million, or an effective tax rate of 36.6% for the nine months ended September 30, 2011. The Income tax provision for the three and nine months ended September 30, 2012 includes a change in estimate related to the expensing of intangible drilling cost due to a voluntary election the Company made upon filing the 2011 tax return in the third quarter. The Company’s effective income tax rate for the three and nine months ended September 30, 2012 and 2011 differed from the federal statutory rate of 35.0% primarily because of state and local income taxes, percentage depletion in excess of cost basis, the domestic production activities deduction and certain other permanent differences.

8. Shareholders’ Equity

During the nine months ended September 30, 2012, dividends were paid at $25.00 per share to shareholders of record effective March 15, 2012, June 25, 2012, and September 24, 2012. During the nine months ended September 30, 2011, dividends were paid at $25.00 per share to shareholders of record effective March 1, 2011, June 15, 2011, and September 15, 2011.

9. Related-Party Transactions

There are certain related party entities that are joint interest and revenue partners in certain of the Company’s properties. Amounts due from such related parties of $1.0 million and $1.3 at September 30, 2012 and December 31, 2011, respectively, are included in Accounts receivable in the Company’s condensed consolidated balance sheets and represent joint interest owner receivables. Amounts due to such related parties of $7.3 million and $6.8 million at September 30, 2012 and December 31, 2011, respectively, are included in Revenues payable in the Company’s condensed consolidated balance sheets and represent revenue owner payables.

10. Commitments and Contingencies

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

 

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

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

 

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negatively affect our production, which will have an adverse effect on our revenues and, as a result, cash flow from operations.

We plan to continue to move away from dry gas in the coming year and to continue to target oil and liquids rich gas plays. We focus our efforts on increasing 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, 2012 and 2011.

 

     Three Months Ended September 30      Nine Months Ended September 30  
     2012      2011      2012      2011  

Average daily production:

           

Oil (Bbl per day)

     3,002         3,187         2,930         2,858   

Natural gas (Mcf per day)

     46,096         54,167         49,372         47,700   

Oil equivalents (Boe per day)

     10,685         12,215         11,159         10,808   

Average prices: (1)

           

Oil ($/Bbl)

   $ 103.75       $ 93.06       $ 100.14       $ 95.08   

Natural gas ($/Mcf)

   $ 4.34       $ 5.37       $ 4.65       $ 5.85   

Oil equivalents ($/Boe)

   $ 47.87       $ 48.10       $ 46.86       $ 50.97   

Production expense ($/Boe)

   $ 8.20       $ 7.26       $ 8.57       $ 8.31   

General and administrative expense ($/Boe)

   $ 4.10       $ 4.28       $ 4.78       $ 4.46   

Net income attributable to RAAM Global (in thousands)

   $ 2,161       $ 9,318       $ 12,480       $ 28,784   

EBITDA (2) (in thousands)

   $ 33,522       $ 33,692       $ 97,724       $ 102,693   

 

(1) 

Average prices presented give effect to our hedging activities and the monetization of gas hedges during February 2012. Please see “Item 1, Note 5, Commodity Derivative Instruments and Hedging Activities” for a discussion of our hedging activities.

(2) 

EBITDA as used herein represents net income before interest expense, income taxes, depreciation, depletion and amortization. We consider EBITDA to be an important indicator for the performance of our business, but not a measure of performance calculated in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). We have included this non-GAAP financial measure because management utilizes this information for assessing our performance and liquidity and as an indicator of our ability to make capital expenditures, service debt and finance working capital requirements. Management believes that EBITDA is a measurement that is commonly used by analysts and some investors in evaluating the performance and liquidity of companies in our industry. In particular, we believe that it is useful to our analysts and investors to understand this relationship because it excludes noncash expense items, such as depletion. We believe that excluding these transactions allows investors to meaningfully trend and analyze the performance and liquidity of our core cash operations. EBITDA should not be considered as an alternative to net income, operating income or any other performance measure derived in accordance with U.S. GAAP or as an alternative to net cash provided by operating activities as a measure of our profitability or liquidity. EBITDA has significant limitations, including that it does not reflect our cash requirements for capital expenditures, contractual commitments, working capital or debt service. In addition, other companies may calculate EBITDA differently than we do, limiting their usefulness as comparative measures.

 

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The following table sets forth a reconciliation of net income as determined in accordance with U.S. GAAP, the most comparable U.S. GAAP measure, to EBITDA for the periods ended September 30, 2012 and 2011.

 

     Three Months Ended September 30      Nine Months Ended September 30  
     2012      2011      2012      2011  
In thousands                            

Net income attributable to RAAM Global

   $ 2,161       $ 9,318       $ 12,480       $ 28,784   

Interest expense

     6,229         5,507         14,208         11,969   

Depreciation, depletion and amortization

     20,736         13,387         60,911         44,450   

Income taxes

     4,396         5,480         10,125         17,490   
  

 

 

    

 

 

    

 

 

    

 

 

 

EBITDA

   $ 33,522       $ 33,692       $ 97,724       $ 102,693   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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Results of Operations

The following table sets forth the unaudited results of operations for the three and nine months ended September 30, 2012 and 2011 in thousands.

 

     Three Months Ended September 30     Nine Months Ended September 30  
     2012     2011     2012     2011  

Revenues:

        

Gas sales

   $ 18,405      $ 26,770      $ 62,872      $ 76,194   

Oil sales

     28,654        27,284        80,409        74,190   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     47,059        54,054        143,281        150,384   

Costs and expenses:

        

Production and delivery costs

     8,060        8,156        26,188        24,508   

Workover costs

     727        4,568        2,167        5,786   

Depreciation, depletion and amortization expenses

     20,736        13,387        60,911        44,450   

General and administrative expenses

     3,602        4,815        13,897        13,929   

Derivative expense (income)

     523        822        2,727        283   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expense

     33,648        31,748        105,890        88,956   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income from operations

     13,411        22,306        37,391        61,428   

Other income (expenses):

        

Interest expense, net

     (6,210     (5,437     (14,156     (11,785

Loss from equity investment

     —          (2,044     —          (2,044

Other, net

     9        (30     226        151   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expenses)

     (6,201     (7,511     (13,930     (13,678
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before taxes

     7,210        14,795        23,461        47,750   

Income tax provision

     4,396        5,480        10,125        17,490   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income including noncontrolling interest

   $ 2,814      $ 9,315      $ 13,336      $ 30,260   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to noncontrolling interest (net of tax)

     653        (3     856        1,476   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to RAAM Global

   $ 2,161      $ 9,318      $ 12,480      $ 28,784   
  

 

 

   

 

 

   

 

 

   

 

 

 

Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011

Revenues

Oil and natural gas production. Oil and natural gas production for the three months ended September 30, 2012 decreased to 1.0 MMBoe from 1.1 MMBoe for the three months ended September 30, 2011. During the three months ended September 30, 2012, gas production decreased 15% and oil production decreased 6%, resulting in a 13% decrease in BOE over the three months ended September 30, 2011. During the third quarter of 2012, oil and gas production was adversely affected by Hurricane Isaac which caused shut-ins during August 2012 and also due to

 

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a twenty day shut in at our large oil facility due to major equipment repairs on the platform. In addition, production from a new well brought online during the third quarter did not offset the normal production declines from our more mature wells.

Total revenues. Total revenues for the three months ended September 30, 2012 decreased to $47.1 million from $54.1 million for the three months ended September 30, 2011. The decrease in revenue was primarily attributable to lower gas prices and lower gas volumes. The effect of the lower gas prices was partially offset by the monetization of gas hedges resulting in additional gas revenues of $4.0 million for forecasted transactions that would have settled during the quarter. The average sales price for the three months ended September 30, 2012 was $47.87 per Boe as compared to $48.10 per Boe for the three months ended September 30, 2011.

Operating costs and expenses

Production and delivery costs. Production and delivery costs were consistent year over year at $8.1 million for the three months ended September 30, 2012 and $8.2 million for the same period in 2011. Production and delivery costs per Boe increased to $8.20 per Boe for the three months ended September 30, 2012 from $7.26 per Boe for the same period in 2011 as a result of decreased oil and gas production described above in the third quarter of 2012, as well as higher costs for contract pumping services and Safety and Environmental Management System (SEMS) compliance efforts.

Workover costs. Our workover costs for the three months ended September 30, 2012 were $0.7 million, or $0.74 per Boe, and $4.6 million in the same period of 2011, or $4.06 per Boe. Workovers are performed on wells that need certain mechanical changes or enhancements to maintain or increase production. During 2011, due to mechanical needs as well as new governmental regulations, the Company performed more workovers during that period than were necessary during the 2012 period.

Depreciation, depletion and amortization expenses. Depreciation, depletion and amortization expenses for the three months ended September 30, 2012 increased to $20.7 million from $13.4 million for the three months ended September 30, 2011. The increase in depreciation, depletion and amortization was primarily due to a higher depletion rate for the third quarter of 2012 applied to a larger net oil and gas property cost base at September 30, 2012 compared to September 30, 2011.

General and administrative expenses. General and administrative expense for the three months ended September 30, 2012 decreased to $3.6 million from $4.8 million for the three months ended September 30, 2011. The decrease in general and administrative expenses was mainly due to lower consultant compensation costs during the 2012 period.

Derivative expense. Derivative expense for the three months ended September 30, 2012 of $0.5 million includes $1.1 million associated with the ineffective portion of our hedged derivative instruments, partially offset by a favorable mark-to-market adjustment for our economic hedges of $0.6 million. Derivative expense for the three months ended September 30, 2011 of $0.8 million relates solely to unfavorable mark-to-market adjustments associated with the ineffective portion of our hedged derivative instruments as we had no economic hedges during that period.

Interest expense, net. Net interest expense increased to $6.2 million for the three months ended September 30, 2012, from $5.4 million for the three months ended September 30, 2011 due to higher debt levels, offset by a reduced weighted average interest rate. Debt balances averaged $250 million during the three months ended September 30, 2012 and $191.8 million during the three months ended September 30, 2011. Interest rates averaged 10.4% and 12.5% during the three months ended September 30, 2012 and 2011, respectively. Amounts of interest expense capitalized to net oil and gas properties during the third quarter of 2012 are discussed in “Item 1, Note 2, Basis of Presentation and Significant Accounting Policies.”

Income tax provision. For the three months ended September 30, 2012, the Company recorded income tax expense of $4.4 million as compared to income tax expense of $5.5 million for the three months ended September 30, 2011.

 

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Income tax expense recognized was based on an effective tax rate calculation of approximately 61% at September 30, 2012 and approximately 37% at September 30, 2011.

The Income tax provision for the three months ended September 30, 2012 includes a change in estimate related to the expensing of intangible drilling costs due to a voluntary election the Company made upon filing the 2011 tax return in the third quarter. The Company’s effective income tax rate for the three months ended September 30, 2012 and 2011 differed from the federal statutory rate of 35.0% primarily because of state and local income taxes, percentage depletion in excess of cost basis, the domestic production activities deduction and certain other permanent differences.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Revenues

Oil and natural gas production. Oil and natural gas production for the nine months ended September 30, 2012 increased to 3.1 MMBoe from 3.0 MMBoe for the nine months ended September 30, 2011. During the nine months ended September 30, 2012, gas production increased 4% and oil production increased 3%, resulting in a 3% increase in BOE over the nine months ended September 30, 2011. During the second quarter, a new oil discovery in California, along with increased production from new wells brought online in the Yegua area onshore Texas and the shallow waters of Louisiana, were partially offset by normal production declines in the more mature offshore fields of West Cameron and Ship Shoal in federal waters and due to lower production in the third quarter due to shut-ins caused by Hurricane Isaac and due to mechanical problems.

Total revenues. Total revenues decreased to $143.3 million for the nine months ended September 30, 2012 from $150.4 million for the nine months ended September 30, 2011. The decrease in revenue was primarily attributable to lower gas prices but was partially offset by the monetization of gas hedges of $9.5 million for forecasted transactions that would have settled during the nine month period. In addition, the increase in oil prices along with increased production from both oil and gas helped to offset the decrease in revenues due to lower gas prices. The average sales price for the nine months ended September 30, 2012 was $46.86 per Boe as compared to $50.97 per Boe for the nine months ended September 30, 2011.

Operating costs and expenses

Production and delivery costs. Production and delivery costs were $26.2 million, or $8.57 per Boe, for the nine months ended September 30, 2012, and $24.5 million, or $8.31 per Boe, for the same period in 2011. The increase in production and delivery costs was primarily attributable to higher costs for contract pumping services and Safety and Environmental Management System (SEMS) compliance efforts offset by lower lift boat and engineering services during the 2012 period than those incurred during the 2011 period.

Workover costs. Our workover costs for the nine months ended September 30, 2012 were $2.2 million, or $0.71 per Boe, and $5.8 million in the same period of 2011, or $1.96 per Boe. Workovers are performed on wells that need certain mechanical changes or enhancements to maintain or increase production. During 2011, due to mechanical needs as well as new governmental regulations, the Company performed more workovers during that period than were necessary during the 2012 period.

Depreciation, depletion and amortization expenses. Depreciation, depletion and amortization expenses for the nine months ended September 30, 2012 increased to $60.9 million from $44.5 million for the nine months ended September 30, 2011. The increase in depreciation, depletion and amortization was primarily due to a larger net oil and gas property cost base at September 30, 2012 compared to September 30, 2011.

General and administrative expenses. General and administrative expenses were flat at $13.9 million for the nine months ended September 30, 2012 and September 30, 2011.

 

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Derivative expense. Derivative expense for the nine months ended September 30, 2012 increased to $2.7 million from $0.3 million for the nine months ended September 30, 2011 primarily due to unfavorable mark-to-market adjustments for our economic hedges of $1.9 million (we had no economic hedges during the nine months ended September 30, 2011) and unfavorable mark-to-market adjustments of $0.8 million during the nine months ended September 30, 2012 associated with the ineffective portion of our hedged derivative instruments compared to $0.3 million for the nine months ended September 30, 2011.

Interest expense, net. Net interest expense increased to $14.2 million for the nine months ended September 30, 2012, from $11.8 million for the nine months ended September 30, 2011 due to higher debt levels, slightly offset by a reduced weighted average interest rate. Debt balances averaged $221.9 million during the nine months ended September 30, 2012 and $184.4 million during the nine months ended September 30, 2011. Interest rates averaged 11.3% and 12.5% during the nine months ended September 30, 2012 and 2011, respectively. Amounts of interest expense capitalized to net oil and gas properties during the period are discussed in “Item 1, Note 2, Basis of Presentation and Significant Accounting Policies.”

Income tax provision. For the nine months ended September 30, 2012, the Company recorded income tax expense of $10.1 million as compared to income tax expense of $17.5 million for the nine months ended September 30, 2011. Income tax expense recognized was based on an effective tax rate calculation of approximately 43.2% at September 30, 2012 and approximately 36.6% at September 30, 2011.

The Income tax provision for the three and nine months ended September 30, 2012 includes a change in estimate related to the expensing of intangible drilling costs due to a voluntary election the Company made upon filing the 2011 tax return in the third quarter. The Company’s effective income tax rate for the three and nine months ended September 30, 2012 and 2011 differed from the federal statutory rate of 35.0% primarily because of state and local income taxes, percentage depletion in excess of cost basis, the domestic production activities deduction and certain other permanent differences.

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.

Capital Expenditures

The Company spent approximately $166 million on capital expenditures during the first nine months of 2012. We anticipate spending an additional $29 million on capital expenditures during the remainder of 2012. Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Our total 2012 capital expenditure budget is approximately $195 million, of which approximately $166 million was expended in the first nine months of 2012. The remaining capital budget of $29 million consists of:

 

   

$9 million for geological and geophysical costs;

 

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$4 million for onshore drilling and development prospects in California;

 

   

$8 million for onshore drilling and development prospects in Texas;

 

   

$5 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 $29 million for these purposes for the remainder of 2012, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. To date, our 2012 capital budget has been funded from debt financing and our cash flows from operations. We believe our existing cash balance, cash flows from operations, borrowings under our Amended Revolving Credit Facility, and proceeds from the sale of other non-core assets should be sufficient to fund the remainder of our 2012 capital expenditure budget.

As of September 30, 2012, we had $50.0 million outstanding under our revolving credit facility and $200 million in Notes outstanding. The borrowing base on our revolving credit facility remains $62.5 million.

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

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

Consolidated Cash Flows

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, 2012 and 2011:

 

     Nine Months Ended September 30  
     2012     2011  
In thousands             

Net cash provided by operating activities

   $ 102,521      $ 116,586   

Net cash used in investing activities

     (150,806     (155,797

Net cash provided by financing activities

     45,206        45,193   
  

 

 

   

 

 

 

Net (decrease) increase in cash and cash equivalents

   $ (3,079   $ 5,982   
  

 

 

   

 

 

 

Cash flows provided by operating activities

Operating activities provided cash totaling $102.5 million during the nine months ended September 30, 2012 as compared to cash provided by operating activities of $116.6 million during the nine months ended September 30, 2011. The decrease in operating cash flows during the nine months ended September 30, 2012 was primarily due to a reduction in net income and higher payments on accounts payable.

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

 

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are difficult to predict. For additional information on the impact of changing commodity 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 $150.8 million during the nine months ended September 30, 2012 as compared to cash used in investing activities of $155.8 million during the same period in 2011. Cash used in investing activities during the nine months ended September 30, 2012 decreased as compared to the same period of 2011 primarily because increased drilling activity onshore Texas and the expansion of a production facility in Louisiana state waters was offset by proceeds from asset sales occurring in the first nine months of 2012 which generated $16.2 million, compared to an asset sale in 2011 that generated $2.1 million in proceeds.

Our capital expenditures for drilling, development and acquisition costs during the nine months ended September 30, 2012 and 2011 are summarized in the following table (in thousands):

 

     Nine Months Ended September 30  
     2012      2011  

Project Area

     

Federal

   $ 2,035       $ 4,249   

Shallow State Waters

     61,193         46,390   

Onshore Texas, Louisiana and Mississippi

     81,370         60,107   

California, Oklahoma and Mid-Continent

     21,668         27,179   
  

 

 

    

 

 

 

Total

   $ 166,266       $ 137,925   
  

 

 

    

 

 

 

Cash flows provided by financing activities

Financing activities provided cash totaling $45.2 million during both the nine months ended September 30, 2012 and September 30, 2011. Cash flows provided by financing activities during the first nine months of 2012 consisted primarily of $50 million in borrowings under our revolving credit facility offset by payments of $4.7 million for shareholder dividends. 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 partially offset by payments of $4.5 million in shareholder dividends and $1.5 million in deferred bond costs.

Off-Balance Sheet Arrangements

As of September 30, 2012, the Company had no off-balance sheet arrangements or guarantees of third party obligations. The Company has no plans to enter into any off-balance sheet arrangements in the foreseeable future.

Oil and Gas Hedging

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

While the use of these hedging arrangements limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements. In addition, the use of hedging transactions may involve basis risk. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize

 

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our exposure to any individual counterparty. All of our hedging transactions are settled based upon reported settlement prices on the NYMEX.

At September 30, 2012, on a BOE basis, commodity derivative instruments were in place covering approximately 66% of our projected oil and natural gas sales through 2012, approximately 51% of our projected oil and natural gas sales for 2013, approximately 42% of our projected oil and natural gas sales for 2014 and approximately 20% of our projected oil and natural gas sales for 2015. Approximately 61% of the Company’s remaining 2012 gas production, approximately 51% of the Company’s 2013 gas production, approximately 53% of the Company’s 2014 gas production, approximately 44% of the Company’s 2015 gas production, approximately 76% of the Company’s remaining 2012 oil production, approximately 51% of the Company’s 2013 oil production, and approximately 22% of the Company’s 2014 oil production will yield minimum prices under the contracts as discussed in “Item 1, Note 5, Commodity Derivative Instruments and Hedging Activities.” Future oil and gas sales prices on other production will fluctuate according to market conditions.

As of September 30, 2012, the Company had entered into the following oil derivative instruments:

 

     NYMEX Contract Price  
     Swaps  
     Volume in Bbls/Mo      Weighted Average
Strike Price
 

Period

     

2012(1)

     81,600       $ 90.71   

2013

     38,494       $ 90.55   

2014(2)

     17,433       $ 85.55   

 

(1) 

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

(2) 

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

 

     NYMEX Contract Price  
     Sell Call      Sell Put  
     Volume in Bbls/Mo      Weighted Average
Strike Price
     Volume in Bbls/Mo      Weighted Average
Strike Price
 

Period

           

2012(1)

     3,680       $ 110.00         59,800       $ 75.00   

2013(2)

     26,584       $ 117.05         21,292       $ 70.00   

2014(3)

     15,925       $ 95.00         15,925       $ 63.60   

 

(1) 

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

(2) 

The Company has entered into two contracts for selling calls, both of which average 13,292 barrels of oil per month, with strike prices of $125.00 and $109.10 for an average strike price of $117.05. In the table below, you will notice that the company has also bought a call for 13,292 barrels of oil per month at the strike price of $125.00.

(3) 

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

 

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     NYMEX Contract Price  
     Buy Call      Buy Put  
     Volume in Bbls/Mo      Weighted Average
Strike Price
     Volume in Bbls/Mo      Weighted Average
Strike Price
 

Period

           

2012

     —         $ —           —         $ —     

2013

     13,292       $ 125.00         13,292       $ 70.00   

2014(1)

     15,925       $ 85.50         —         $ —     

 

(1) 

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

As of September 30, 2012, the Company had entered into the following natural gas derivative instruments:

 

     NYMEX Contract Price  
     Swaps  
     Volume in Mbtu/Mo      Weighted Average
Strike Price
 

Period

     

2012(1)

     957,000       $ 3.10   

2013

     644,950       $ 3.76   

2014

     443,767       $ 3.96   

2015

     252,475       $ 4.74   

 

(1) 

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

The swap transactions were designated as cash flow hedges; the option contracts do not follow hedge accounting; however, the Company considers the contracts as economic hedges. Please see “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.

Financing Facilities

Senior Secured Notes

On September 24, 2010, the Company 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 Amended Revolving Credit Facility and the remainder of the proceeds was used to fund a

 

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portion of our planned capital expenditures for development and drilling. On May 10, 2011, the Company closed an exchange offer registering substantially all of the Original Notes.

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

As of September 30, 2012, a total of $200.0 million notional amount of the Notes was outstanding. The carrying amount of the Notes was $200.0 million as of September 30, 2012.

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

Amended Revolving Credit Facility

The borrowing base remains $62.5 million of which $50.0 million was drawn at September 30, 2012. The Credit Agreement governing the Amended Revolving Credit Facility includes covenants restricting certain of the Company’s financial ratios, including its current ratio and a debt coverage ratio, and a limitation on general and administrative expenses. The covenants also include limitations on borrowings, investments, and distributions. The Company was in compliance with these debt covenants at September 30, 2012. The maturity date is July 1, 2015.

Borrowings under our Amended Revolving Credit Facility are limited to a borrowing base calculated based on our proved reserves. Borrowings bear interest at a floating rate equal to either the prime rate of interest in effect from time to time (plus a certain percentage in certain circumstances) or LIBOR plus a certain percentage based on the amount of availability under our Amended Revolving Credit Facility.

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

Critical Accounting Policies and Estimates

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

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

 

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Recently Issued Accounting Pronouncements

See “Item 1, Note 2, Basis of Presentation and Significant Accounting Policies” for a discussion of recently issued accounting pronouncements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, 2011.

We are exposed to a variety of market risks including commodity price risk, credit risk and interest rate risk. We address these risks through a program of risk management which may include the use of derivative instruments. We do not enter into derivative or other financial instruments for speculative or trading purposes.

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. Hypothetical changes in commodity prices chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations. However, since it is not possible to accurately predict future changes in commodity prices, this hypothetical change may not necessarily be an indicator of probable future fluctuations. Based on our average daily production for the nine months ended September 30, 2012, our annual revenue would increase or decrease by approximately $10.7 million for each $10.00 per barrel change in crude oil prices and $18.0 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 “Item 1, Note 3, Fair Value Measurements” and “Item 1, Note 5, Commodity Derivative Instruments and Hedging Activities” included in this report.

Credit Risk

We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through joint interest receivables ($3.2 million at September 30, 2012) and the sale of our crude oil and natural gas production, which we market to energy marketing companies, refineries and affiliates ($31.7 million in receivables at September 30, 2012). Joint interest receivables arise from billing entities who own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. In order to minimize our exposure to credit risk we request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. In this manner, we reduce credit risk. We also have the right to place

 

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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. The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of those contracts.

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. We had $50 million outstanding under the Amended Revolving Credit Facility at September 30, 2012. 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, 2012 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting. There was no change in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended September 30, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting with the limited exception of changes made in preparation for our first management report on internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the information set forth in this Form 10-Q, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our 2011 Form 10-K that was filed with the SEC on March 27, 2012 and in Part II, “Item 1A. Risk Factors” in our Form 10-Q for the quarter ended March 31, 2012 that was filed with the SEC on May 11, 2012, which could materially affect our business, financial condition or future results. There have been no

 

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material changes to these risk factors. 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 adversely affect our business, financial condition or results of operations.

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
    By:   RAAM Global Energy Company
November 13, 2012       By:   /s/ Jeffrey Craycraft
     

Jeffrey Craycraft

Chief Financial Officer

(Duly Authorized Officer and Principal Financial Officer)

 

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Exhibit Index

 

3.1    Certificate of Incorporation of RAAM Global Energy Company, dated November 19, 2003 (incorporated by reference from Exhibit 3.1 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
3.2    Bylaws of RAAM Global Energy Company (incorporated by reference from Exhibit 3.2 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).
31.1 *    Certification of Chief Executive Officer Pursuant to Rule 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended.
31.2 *    Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended.
32.1 **    Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2 **    Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
101***    Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011; (ii) our Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2012 and 2011; (iii) our Condensed Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2012 and 2011; (iv) our Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2012 and 2011; and (v) the notes to our unaudited Condensed Consolidated Financial Statements.

 

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

 

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