RAAM Global Energy Co - FORM 10-Q/A

Attached files

file	filename
EXCEL - IDEA: XBRL DOCUMENT - RAAM Global Energy Co	Financial_Report.xls
EX-32.1 - EX-32.1 - RAAM Global Energy Co	d566917dex321.htm
EX-32.2 - EX-32.2 - RAAM Global Energy Co	d566917dex322.htm
EX-31.1 - EX-31.1 - RAAM Global Energy Co	d566917dex311.htm
EX-31.2 - EX-31.2 - RAAM Global Energy Co	d566917dex312.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q/A

(Amendment No. 1)

(Mark One)

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

For the quarterly period ended March 31, 2012

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

For the transition period from to .

Commission File No. 333-172897

RAAM Global Energy Company

(Exact name of registrant as specified in its charter)


Delaware		20-0412973
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1537 Bull Lea Rd., Suite 200

Lexington, Kentucky

40511

(Address of principal executive offices)

(Zip Code)

(859) 253-1300

(Registrant’s telephone number, including area code)

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

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

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


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

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

As of May 9, 2012, there were 62,500 shares of common stock, $0.01 par value, outstanding.

EXPLANATORY NOTE

Unless the context requires otherwise, references to “RAAM,” “we,” “our,” “us” or like terms refer to RAAM Global Energy Company, it subsidiaries and entities it manages or operates.

This Amendment No. 1 on Form 10-Q/A (the “Amendment”) amends our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2012, originally filed with the Securities and Exchange Commission (“SEC”) on May 11, 2012 (the “Original Filing”). As disclosed in a Current Report on Form 8-K filed with the SEC on May 20, 2013, the Audit Committee of the Board of Directors concluded on May 15, 2013 that the Company would restate its consolidated financial statements as of and for the fiscal years ended December 31, 2012, 2011, 2010, 2009 and 2008 included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012 and interim financial statements included in the Company’s quarterly reports on Form 10-Q for the quarters ending March 31, 2012, June 30, 2012 and September 30, 2012. The restated consolidated financial statements correct certain non-cash errors in such financial statements associated with the measurement of depletion expense on its oil and gas properties and related impacts on the limitation of capitalized costs, the accounting for certain derivative transactions which were previously accounted for as cash flow hedges incorrectly, and to reverse the recognition of a gain on an unevaluated property sale which was not subject to amortization, which also impacted the measurement of subsequent periods’ depletion expenses. As a result of the error correction on the Company’s derivative transactions, there are no other components of comprehensive income aside from net income, and accordingly, the statement of comprehensive income is no longer presented.

The Company also corrected a classification error for production taxes, which were previously netted with oil and gas sales, to a new line item within the operating expense section of the consolidated statement of operations.

These error corrections resulted in no changes to the Company’s previously reported cash flow from operating activities. As a result of the foregoing, we are restating herein our consolidated balance sheets as of March 31, 2012 and December 31, 2011, and our consolidated statements of operations and cash flows for the periods ending March 31, 2012 and 2011. Pursuant to Rule 12b-15 under the Securities Exchange Act of 1934 (the “Exchange Act”), the following items have been amended and restated in their entirety:

•

Part I, Item 1. Financial Statements

•

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

•

Part I, Item 3. Quantitative and Qualitative Disclosures About Market Risk

•

Part I, Item 4. Controls and Procedures

Additionally, the certifications pursuant to Section 302 and Section 906 of the Sarbanes-Oxley Act of 2002, filed as exhibits to the Original Filing, have been re-executed as of the date of the Form 10-Q/A. Accordingly, Item 6 of Part II has also been amended and restated.

The Company has not modified or updated disclosures presented in the Original Filing, except to reflect the effects of the restatement of the Company’s financial statements, as described above. Accordingly, this Amendment does not reflect events occurring after the date of the Original Filing and does not modify or update those disclosures affected by subsequent events, except as specifically referenced herein. Information not affected by the restatement is unchanged and reflects the disclosures made at the time of the Original Filing. References to the “Form 10-Q/A” herein shall refer to the Form 10-Q as amended by this Amendment No. 1 to the Form 10-Q.

TABLE OF CONTENTS


			Page
Cautionary Note Regarding Forward-Looking Statements				4
Part I. Financial Information				6
	Item 1. Financial Statements			6
		Condensed Consolidated Balance Sheets		6
		Condensed Consolidated Statements of Operations		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			21
	Item 3. Quantitative and Qualitative Disclosures About Market Risk			32
	Item 4. Controls and Procedures			33

Part II. Other Information
	Item 6. Exhibits			33

SIGNATURES				34

Exhibit Index				35

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

•

Forward-looking oil and natural gas reserve estimates;

•

future financial and operating performance and results;

•

business and financial strategy and budgets;

•

market prices;

•

drilling of wells and the anticipated results thereof;

•

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

•

competition and government regulations;

•

prospect development;

•

property acquisitions and sales; and

•

plans, forecasts, objectives, expectations and intentions.

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

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

•

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

•

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

•

ability to raise additional capital to fund future capital expenditures;

•

cash flow and liquidity;

•

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

•

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

•

geological concentration of our reserves;

•

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

•

operating hazards attendant to the oil and natural gas business;

•

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

•

delays in anticipated start-up dates;

•

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

•

ability to find and retain skilled personnel;

•

strength and financial resources of competitors;

•

federal and state regulatory developments and approvals;

•

environmental risks;

•

changes in interest rates;

•

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

•

worldwide political and economic conditions.

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

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

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

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except for share amounts)

(unaudited)


	March 31, 2012			December 31, 2011
	(As Restated)			(As Restated)
Assets
Current assets:
Cash and cash equivalents	$	18,915		$	51,743
Accounts receivable, net of $1,005 provision for bad debts in 2012 and 2011		4,667			5,642
Revenues receivable		28,112			31,532
Income taxes receivable		2,474			2,118
Deferred tax asset		2,094			—
Commodity derivatives—current portion		7,112			12,674
Prepaid assets		3,289			4,945
Other current assets		3,665			3,919

Total current assets		70,328			112,573

Oil and gas properties (full-cost method):
Properties being amortized		1,220,262			1,155,894
Properties not subject to amortization		109,774			111,621
Less accumulated depreciation, depletion, and amortization		(670,326	)		(651,608	)

Net oil and gas properties		659,710			615,907

Other assets:
Other capitalized assets, net		7,092			7,183
Commodity derivatives		3,417			3,191
Other		5,187			5,698

Total other assets		15,696			16,072

Total assets	$	745,734		$	744,552

See accompanying notes to the condensed consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except for share amounts)

(unaudited)


	March 31, 2012			December 31, 2011
	(As Restated)			(As Restated)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	42,181		$	52,969
Revenues payable		24,820			29,319
Interest payable—senior secured notes		—			6,250
Current taxes payable		390			399
Advances from joint interest partners		227			1,019
Commodity derivatives—current portion		11,146			—
Asset retirement obligations—current portion		1,782			1,778
Long-term debt—current portion		130			1,929
Deferred income taxes—current portion		—			3,109

Total current liabilities		80,676			96,772

Other liabilities:
Commodity derivatives		8,396			4,244
Asset retirement obligations		25,638			25,010
Long-term debt		2,699			2,733
Senior secured notes		199,969			199,972
Deferred income taxes		121,869			112,963
Other long-term liabilities		499			467

Total other liabilities		359,070			345,389

Total liabilities		439,746			442,161

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		249,129			245,694

Total shareholders’ equity attributable to RAAM Global		305,871			302,436
Noncontrolling interest		117			(45	)

Total shareholders’ equity		305,988			302,391

Total liabilities and shareholders’ equity	$	745,734		$	744,552

See accompanying notes to the condensed consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

(unaudited)


	Three Months Ended March 31
	2012			2011
	(As Restated)			(As Restated)
Revenues:
Gas sales	$	16,381		$	18,420
Oil sales		28,098			23,160
Realized and unrealized gains (losses) on derivatives, net		6,417			(5,510	)

Total revenues		50,896			36,070

Costs and expenses:
Production and delivery costs		8,394			7,462
Production taxes		2,426			1,865
Workover costs		961			432
Depreciation, depletion and amortization expenses		19,068			16,985
General and administrative expenses		5,622			4,379

Total operating expense		36,471			31,123


Income from operations		14,425			4,947

Other income (expenses):
Interest expense, net		(6,107	)		(3,399	)
Other, net		192			194

Total other income (expenses)		(5,915	)		(3,205	)

Income before taxes		8,510			1,742

Income tax provision (benefit)		3,351			(1,590	)

Net income including noncontrolling interest	$	5,159		$	3,332


Net income attributable to noncontrolling interest (net of tax)		117			454

Net income attributable to RAAM Global	$	5,042		$	2,878

See accompanying notes to the condensed consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(unaudited)


	Three Months Ended March 31
	2012			2011
	(As Restated)			(As Restated)
Operating activities
Net income including noncontrolling interest	$	5,159		$	3,332
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization expenses		19,525			17,419
Deferred income taxes		3,703			(1,555	)
Changes in assets and liabilities:
Accounts and revenues receivable		4,394			1,157
Income tax receivables		(356	)		—
Prepaids and other current assets		1,909			40
Change in derivatives, net		20,634			11,267
Accounts payable and accrued liabilities		(10,847	)		(4,359	)
Revenues payable		(4,499	)		1,940
Interest payable on Senior Notes		(6,250	)		(5,048	)
Current taxes payable		(8	)		(67	)
Other long-term liabilities		31			—

Net cash provided by operating activities		33,395			24,126

Investing activities
Change in advances from joint interest partners		(792	)		2,443
Additions to oil and gas properties and equipment		(62,034	)		(25,117	)
Proceeds from net sales of oil and gas properties		—			13,384

Net cash used in investing activities		(62,826	)		(9,290	)

Financing activities
Payments on borrowings		(1,832	)		(1,031	)
Payment of dividends		(1,563	)		(1,500	)
Other		(2	)		48

Net cash used in financing activities		(3,397	)		(2,483	)


(Decrease) increase in cash and cash equivalents		(32,828	)		12,353
Cash and cash equivalents, beginning of period		51,743			81,032

Cash and cash equivalents, end of period	$	18,915		$	93,385

See accompanying notes to the condensed consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Nature of Business

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

2. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

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

The Condensed Consolidated Balance Sheet as of December 31, 2011, was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States (“U.S. GAAP”). Certain notes and other information have been condensed or omitted from the interim financial statements presented in this quarterly report. Therefore, these financial statements and notes should be read in conjunction with the Company’s audited annual consolidated financial statements 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 $1.4 million for the three months ended March 31, 2012 and 2011, respectively. The Company capitalized interest of $0.6 million and $1.8 million during the three months ended March 31, 2012 and 2011, respectively, related to significant properties not subject to amortization.

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

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

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

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

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

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

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

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

Derivative 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 derivative 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.

The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on anticipated settlement dates. The Company has not designated its derivative instruments as cash flow hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and records the unrealized changes in fair value in Realized and unrealized gains (losses) on derivatives, net in the accompanying consolidated statements of operations. All realized cash settlements of derivative activities are also recorded in Realized and unrealized gains (losses) on derivatives, net in the accompanying consolidated statements of operations. See Note 5, Commodity Derivative Instruments and Derivative Activities included elsewhere in this quarterly report for further details on the unrealized changes in fair value between periods and the realized cash settlements received or paid in each reporting period.

Accounting for Asset Retirement Obligations

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

depreciation of $15.4 million and $15.1 million, respectively. Accretion of the discounted asset retirement obligations is recognized as an increase in the carrying amount of the liability and as an expense in Depreciation, depletion and amortization expenses on the accompanying condensed consolidated statement of operations.

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


*In thousands*
Balance of ARO as of January 1, 2012	$	26,788
Accretion expense		191
Additions		441
Settlement of ARO		—
Changes in ARO estimate		—

Balance of ARO as of March 31, 2012	$	27,420

Operating Segments

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

New Accounting Pronouncements

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

•

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

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


	Fair Value Measurements Using Significant Other Observable Inputs (Level 2)
Description	March 31, 2012			December 31, 2011
*In thousands*
Assets:
Fair value of commodity derivatives—current assets	$	7,112		$	12,674
Fair value of commodity derivatives—long-term assets		3,417			3,191

Total Assets	$	10,529		$	15,865


Liabilities:
Fair value of commodity derivatives—current liabilities	$	(11,146	)	$	—
Fair value of commodity derivatives—long-term liabilities		(8,396	)		(4,244	)

Total Liabilities	$	(19,542	)	$	(4,244	)

2015 Senior Secured Notes

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

4. Accounts and Revenues Receivable

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

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

5. Commodity Derivative Instruments and Derivative 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.

All of the Company’s commodity derivative transactions are settled based on reported settlement prices on the New York Mercantile Exchange (“NYMEX”). The estimated fair value of these transactions is based on various factors that include closing exchange prices on the NYMEX, over-the-counter quotations, volatility and the time value of options. The calculation of the fair value of collars and floors utilizes the Black-Scholes option-pricing model. Since these transactions were not designated as cash flow hedges for accounting purposes, the Company marks its derivative instruments to fair value and records the unrealized changes in fair value in Realized and unrealized gains (losses) on derivatives, net in the accompanying consolidated statements of operations. All realized cash settlements of derivative activities are also recorded in Realized and unrealized gains (losses) on derivatives, net in the accompanying consolidated statements of operations. See Note 2, Basis of Presentation and Significant Accounting Policies, for additional information on the Company’s derivative activities.

The table below summarizes the amount of derivative instrument gains and losses reported in the consolidated statements of operations as Realized and unrealized gains (losses) on derivative instruments, net, for the periods indicated. These derivative instruments are not designated as hedging instruments for accounting purposes.


	Three Months Ended March 31
	2012			2011
	(As Restated)			(As Restated)
Commodity derivatives:
Realized gains	$	27,051		$	5,757
Unrealized losses		(20,634	)		(11,267	)

Realized and unrealized gains (losses) on derivatives, net	$	6,417		$	(5,510	)

Due to the volatility of oil and natural gas prices, the estimated fair values of the Company’s commodity derivative instruments are subject to large fluctuations from period to period. The Company has experienced the effects of these commodity price fluctuations in both the current period and prior periods and expects that volatility in commodity prices will continue.

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


Remaining Contract Term	Contract Type		Volume in MMBtus/ Month		NYMEX Strike Price
April 2012—December 2012		Swap		61,111	$	3.05
April 2012—December 2012		Swap		61,111	$	3.05
April 2012—December 2012		Swap		376,556	$	3.00
April 2012—December 2012		Swap		152,778	$	3.67
April 2012—December 2012		Swap		220,444	$	3.00


April 2012—December 2012	Swap	309,233	$	2.94
January 2013—September 2013	Swap	90,556	$	3.70
January 2013—December 2013	Swap	152,083	$	3.67
January 2013—December 2013	Swap	152,083	$	3.81
January 2013—December 2013	Swap	150,542	$	3.81
January 2013—December 2013	Swap	122,325	$	3.79
January 2014—June 2014	Swap	150,833	$	4.09
January 2014—December 2014	Swap	152,083	$	3.67
January 2014—December 2014	Swap	158,833	$	4.15
January 2014—December 2014	Swap	79,850	$	4.00
July 2014—December 2014	Swap	30,667	$	4.00
January 2015—December 2015	Swap	167,042	$	4.94
January 2015—December 2015	Swap	85,433	$	4.35

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


Remaining Contract Term	Contract Type	Volume in BBls/ Month		NYMEX Strike Price
April 2012—September 2012	Swap		24,400	$	82.25
April 2012—December 2012	Call		3,667	$	110.00
April 2012—December 2012	Swap		17,478	$	100.02
April 2012—December 2012	Swap		17,433	$	100.30
April 2012—December 2012	Put		59,583	$	75.00
April 2012—June 2012	Swap		6,000	$	88.52
April 2012—June 2012	Swap		6,000	$	87.05
April 2012—June 2012	Swap		5,000	$	87.50
July 2012—September 2012	Swap		12,000	$	88.76
July 2012—September 2012	Swap		5,000	$	87.80
October 2012—December 2012	Swap		39,867	$	84.00
January 2013—June 2013	Swap		21,117	$	84.70
January 2013—December 2013	Call		13,292	$	125.00
January 2013—December 2013	Swap		8,833	$	95.72
January 2013—December 2013	Put		21,292	$	70.00
July 2013—December 2013	Swap		15,333	$	85.50
January 2014—June 2014	Swap		24,133	$	85.40
July 2014—September 2014	Swap		21,467	$	85.90

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

6. Debt

2015 Senior Secured Notes

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

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

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

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

As of May 15, 2013, the Company was not in compliance with a non-financial covenant included within Section 4.03 of the 2015 Senior Secured Notes Indenture regarding the non-timely filing of its consolidated financial statements. The 2015 Senior Secured Notes Indenture includes customary grace and cure periods of 120 days, and it is probable that the violation will be cured within this period, thus preventing the obligation from becoming callable. Accordingly, no reclassification of the outstanding 2015 Senior Secured Notes to current was required.

Amended Revolving Credit Facility

On November 29, 2011, the Company’s revolving credit facility was amended (the “Amended Revolving Credit Facility”). The borrowing base remains $62.5 million which was undrawn at March 31, 2012. The Credit Agreement governing the amended revolving credit facility includes covenants restricting certain of the Company’s financial ratios, including its current ratio and a debt coverage ratio, and a limitation on general and administrative expenses. The covenants also include limitations on borrowings, investments, and distributions. The Company is in compliance with these debt covenants at March 31, 2012. As of May 30, 2013, the Company was not in compliance with a non-financial covenant included within Section 6.2(b) of the Credit Agreement regarding the non-timely filing of its consolidated financial statements. The Company has received a waiver from its lenders through August 15, 2013 with respect to this violation and anticipates the violation will be cured within this period. Accordingly, no reclassification of the outstanding obligation to current was required.

Promissory Note

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

Finance Agreement

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

7. Income Taxes

The Income tax provision for the three months ended March 31, 2012 was $3.4 million or an effective tax rate of 39.4%, compared to an income tax benefit of $1.6 million or an effective tax rate of 91.2% for the three months ended March 31, 2011. The three months’ effective tax rates have been impacted by the deferred tax portion of certain non-cash items corrected in the restatement process and the resulting change in pre-tax income (loss) for these periods. Restated effective tax rates for the years ended December 31, 2012 and 2011 as disclosed in the Company’s Amendment No. 1 of Form 10-K/A for the fiscal year ended December 31, 2012 are 40.9% and 40.5%, respectively. See Note 12, Restatement of Previously Issued Financial Statements for further information on the restatement. The Company’s effective income tax rate for the three months ended March 31, 2012 and 2011, exclusive of all restatement items, differed from the federal statutory rate of 35.0% primarily because of state and local income taxes, percentage of depletion in excess of basis, the domestic production activities deduction and certain other permanent differences.

8. Shareholders’ Equity

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

9. Related-Party Transactions

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

10. Commitments and Contingencies

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

11. Subsidiary Guarantors of Parent Company Debt

During 2010 and 2011, RAAM Global issued the Notes, described in Note 6, Debt. Each of RAAM Global’s 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 subject to certain customary automatic subsidiary release provisions.

12. Restatement of Previously Issued Financial Statements

The Company is restating the consolidated financial statements for 2011 and 2012. During the preparation of the first quarter 2013 financial statements, the Company identified certain errors as follows:

•

The measurement of depletion expense on its oil and gas properties and related impacts on the limitation of capitalized costs, which resulted in a decrease to depletion expense of $0.1 million for the three months ended March 31, 2011 and an increase to depletion expense of $0.1 million for the three months ended March 31, 2012.

•

The accounting for certain derivative transactions which were previously accounted for as cash flow hedges incorrectly, resulted in the current recognition of all unrealized mark-to-market adjustments, previously recorded in accumulated other comprehensive income (loss) of $7.9 million and $8.9 million for December 31, 2011 and March 31, 2012, net of tax, respectively, to the realized and unrealized gain (loss) on derivatives, net, in the consolidated statements of operations. Additionally, the previously recognized unrealized gains and losses on these instruments recorded as derivative (income) expense was reclassified to the realized and unrealized gains (losses) on derivatives, net, which was ($0.2) million and $0.1 million, for March 31, 2011 and 2012, respectively. Lastly, the amounts previously recognized in oil and gas sales for these derivative transactions were reclassified to realized and unrealized gains (losses) on derivatives, net, which was approximately $6.7 million and $7.8 million for gas sales for the three months ended March 31, 2011 and 2012, respectively, and ($1.0) million and ($2.8) million for oil sales, respectively.

•

The reversal of a $48.2 million gain on an unevaluated property sale in 2008 which was not subject to amortization also impacted the measurement of subsequent periods’ depletion expenses included above. The impact of this error was included as a correction of the prior period error affecting the Company’s beginning equity, net of tax, on January 1, 2010 opening retained earnings.

•

The classification of production taxes, which were previously netted with oil and gas sales, to a new line item within the operating expense section of the consolidated statement of operations, was $1.9 million and $2.4 million at March 31, 2011 and 2012, respectively.

To correctly reflect the correction of these errors for periods prior to 2011, including the adjustments to depletion expenses, limitations of capitalized oil and gas costs, the accounting for derivatives, and the unevaluated property sale, the Company recorded a $21.3 million increase, net of tax, to ending 2010 retained earnings and a $6.0 million decrease, net of tax, to ending 2010 accumulated other comprehensive income in the consolidated statement of shareholders’ equity to adjust the previously reported balance to the As Restated amounts as of this date. The impact of the errors is presented in the tables below (in thousands).


	March 31, 2012
	As Previously Reported			Adjustments			As Restated
Consolidated Balance Sheet
Properties being amortized	$	1,267,640		$	(47,378	)	$	1,220,262
Accumulated depreciation, depletion, and amortization		(738,677	)		68,351			(670,326	)
Net oil and gas properties		638,737			20,973			659,710
Total assets		724,761			20,973			745,734
Deferred income taxes		114,039			7,830			121,869


Total other liabilities		351,240		7,830			359,070
Total liabilities		431,916		7,830			439,746
Retained earnings		227,114		22,015			249,129
Accumulated other comprehensive income, net of taxes		8,872		(8,872	)		—
Total shareholders’ equity attributable to RAAM		292,728		13,143			305,871
Total shareholders’ equity		292,845		13,143			305,988
Total liabilities and shareholders’ equity		724,761		20,973			745,734
Consolidated Statements of Operations
Gas sales	$	23,023	$	(6,642	)	$	16,381
Oil sales		24,081		4,017			28,098
Realized and unrealized gains on derivatives, net		—		6,417			6,417
Total revenues		47,104		3,792			50,896
Production taxes		—		2,426			2,426
Depreciation, depletion and amortization		18,965		103			19,068
Derivative expense		141		(141	)		—
Total operating expense		34,083		2,388			36,471
Income from operations		13,021		1,404			14,425
Income before taxes		7,106		1,404			8,510
Income tax provision		2,825		526			3,351
Net income including noncontrolling interest		4,281		878			5,159
Net income attributable to RAAM Global		4,164		878			5,042
Consolidated Statements of Cash Flows
Net income including noncontrolling interest	$	4,281	$	878		$	5,159
Depreciation, depletion and amortization		19,421		104			19,525
Deferred income taxes		3,741		(38	)		3,703
Change in derivatives, net		21,578		(944	)		20,634


	December 31, 2011
	As Previously Reported			Adjustments			As Restated
Consolidated Balance Sheet
Properties being amortized	$	1,203,272		$	(47,378	)	$	1,155,894
Accumulated depreciation, depletion, and amortization		(720,062	)		68,454			(651,608	)
Net oil and gas properties		594,831			21,076			615,907
Total assets		723,476			21,076			744,552
Deferred income taxes		105,095			7,868			112,963
Total other liabilities		337,521			7,868			345,389
Total liabilities		434,293			7,868			442,161
Retained earnings		224,558			21,136			245,694
Accumulated other comprehensive income, net of taxes		7,928			(7,928	)		—
Total shareholders’ equity attributable to RAAM		289,228			13,208			302,436
Total shareholders’ equity		289,183			13,208			302,391
Total liabilities and shareholders’ equity		723,476			21,076			744,552


	March 31, 2011
	As Previously Reported			Adjustments			As Restated
Consolidated Statements of Operations
Gas sales	$	24,315		$	(5,895	)	$	18,420
Oil sales		21,158			2,002			23,160
Realized and unrealized losses on derivatives, net		—			(5,510	)		(5,510	)
Total revenues		45,473			(9,403	)		36,070
Production taxes		—			1,865			1,865
Depreciation, depletion and amortization		17,139			(154	)		16,985
Derivative income		(247	)		247			—
Total operating expense		29,165			1,958			31,123
Income from operations		16,308			(11,361	)		4,947
Income before taxes		13,103			(11,361	)		1,742
Income tax provision (benefit)		2,655			(4,245	)		(1,590	)
Net income including noncontrolling interest		10,448			(7,116	)		3,332
Net income attributable to RAAM Global		9,994			(7,116	)		2,878
Consolidated Statements of Cash Flows
Net income including noncontrolling interest	$	10,448		$	(7,116	)	$	3,332
Depreciation, depletion and amortization		17,574			(155	)		17,419
Deferred income taxes		(1,770	)		215			(1,555	)
Change in derivatives, net		4,211			7,056			11,267

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

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

Overview

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

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

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

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

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

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

Recent Developments

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

How We Evaluate Our Operations

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


	Three Months Ended March 31
	2012		2011
	(As Restated)		(As Restated)
Average daily production:
Oil (Bbl per day)		2,804		2,520
Natural gas (Mcf per day)		51,658		42,995
Oil equivalents (Boe per day)		11,414		9,686
Average prices:⁽¹⁾
Oil ($/Bbl)	$	110.11	$	102.10
Natural gas ($/Mcf)	$	3.48	$	4.76
Oil equivalents ($/Boe)	$	49.00	$	41.38

Production expense ($/Boe)	$	8.08	$	8.56
General and administrative expense ($/Boe)	$	5.41	$	5.02
Net income attributable to RAAM Global (in thousands)	$	5,042	$	2,878
Adjusted EBITDA ⁽²⁾ (in thousands)	$	54,217	$	32,976

⁽¹⁾	Average prices presented do not give effect to our derivative transactions or the monetization of gas derivatives during February 2012. Please see Note 5, Commodity Derivative Instruments and Derivative Activities for a discussion of our derivative activities.

⁽²⁾

Adjusted EBITDA as used herein represents net income before interest expense, unrealized gains (losses) on derivatives, income taxes, and depreciation, depletion and amortization. We present Adjusted EBITDA because some investors believe it is an important supplemental measure of our performance, frequently used in evaluating companies in our industry. Adjusted EBITDA is not a measurement of our financial performance under accounting principles generally accepted in the United States (“U.S. GAAP”) and should not be considered as an alternative to net income, operating income or any other performance measure derived in accordance with U.S. GAAP or as an alternative to net cash provided by operating activities as a measure of our profitability or liquidity. Adjusted 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 Adjusted EBITDA differently than we do, limiting their usefulness as comparative measures.

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


	Three Months Ended March 31
	2012		2011
*In thousands*	(As Restated)		(As Restated)
Net income attributable to RAAM Global	$	5,042	$	2,878
Unrealized losses on derivatives		20,634		11,267
Interest expense		6,122		3,436
Depreciation, depletion and amortization		19,068		16,985
Income taxes		3,351		(1,590	)

Adjusted EBITDA	$	54,217	$	32,976

The table below shows realized and unrealized gains and losses on derivatives from operations, which are recorded as Realized and unrealized gains on derivatives, net in our consolidated statement of operations for the periods indicated. See Item 1, Note 5, Commodity Derivative Instruments and Derivative Activities for more information on our derivatives.


	Three Months Ended March 31,
	2012			2011
	(In thousands)
	(As Restated)			(As Restated)
Realized gains (losses) on derivatives, net:
Oil	$	(2,764	)	$	(925	)
Natural gas		29,815			6,682

Realized gains on derivatives, net		27,051			5,757
Unrealized losses on derivatives, net		(20,634	)		(11,267	)

Realized and unrealized gains (losses) on derivatives, net	$	6,417		$	(5,510	)

The table below shows realized revenues from oil and gas sales. Sales revenues are summarized with realized gains and losses on derivative settlements.


	Three Months Ended March 31,
	2012			2011
	(In thousands)
	(As Restated)			(As Restated)
Oil sales	$	28,098		$	23,160
Realized losses on oil derivatives, net		(2,764	)		(925	)

Total realized revenues from oil sales	$	25,334		$	22,235

Gas sales	$	16,381		$	18,420
Realized gains on gas derivatives, net		29,815			6,682

Total realized revenues from gas sales	$	46,196		$	25,102

Total realized revenues from oil and gas sales as used herein represents oil and gas sales combined with realized gains and losses on derivatives settlements. We consider Total realized revenues from oil and gas sales 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 Total realized revenues from oil and gas sales is a measurement that can be 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 includes the effect on revenues of cash received or paid on derivative settlements. We believe that including these transactions allows investors to meaningfully trend and analyze the performance and liquidity of our

core cash operations. Total realized revenues from oil and gas sales 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. Total realized revenues from oil and gas sales 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 Total realized revenues differently than we do, limiting their usefulness as comparative measure.

The table below shows the average realized price per unit from operations including the effects of commodity derivative instruments realized for the periods presented:


	Three Months Ended March 31,
	2012			2011
	(As Restated)			(As Restated)
Oil:
Average sales price ($/Bbl)	$	110.11		$	102.10
Effects of commodity derivatives ($/Bbl)		(10.83	)		(4.08	)

Average realized Price ($/Bbl)	$	99.28		$	98.02

Natural Gas:
Average sales price ($/Mcf)	$	3.48		$	4.76
Effects of commodity derivatives ($/Mcf)		6.35			1.73

Average realized Price ($/Mcf)	$	9.83		$	6.49

Totals:
Average sales price ($/Boe)	$	49.00		$	41.38
Effects of commodity derivatives ($/Boe)		19.87			12.92

Average realized Price ($/Boe)	$	68.87		$	54.30

Results of Operations

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


	Three Months Ended March 31
	2012			2011
	(As Restated)			(As Restated)
Revenues:
Gas sales	$	16,381		$	18,420
Oil sales		28,098			23,160
Realized and unrealized gains (losses) on derivatives, net		6,417			(5,510	)

Total revenues		50,896			36,070
Costs and expenses:
Production and delivery costs		8,394			7,462
Production taxes		2,426			1,865
Workover costs		961			432
Depreciation, depletion and amortization expenses		19,068			16,985
General and administrative expenses		5,622			4,379

Total operating expense		36,471			31,123

Income from operations		14,425			4,947
Other income (expenses):
Interest expense, net		(6,107	)		(3,399	)
Other, net		192			194

Total other income (expenses)		(5,915	)		(3,205	)

Income before taxes		8,510			1,742
Income tax provision (benefit)		3,351			(1,590	)

Net income including noncontrolling interest	$	5,159		$	3,332

Net income attributable to noncontrolling interest (net of tax)		117			454

Net income attributable to RAAM Global	$	5,042		$	2,878

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

Revenues

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

Total revenues. Total revenues for the three months ended March 31, 2012 increased to $50.9 million from $36.1 million for the three months ended March 31, 2011. Gas revenues (exclusive of derivatives) decreased $2.0 million or 11% due to lower gas prices which declined by 27% from an average price of $4.76 for the three months ended March 31, 2011 to an average gas price of $3.48 for the three months ended March 31, 2012. Realized gas revenues (including realized revenues from derivative activities) increased by $21.1 million or 84% due mainly to the monetization of gas derivatives of $23.3 million executed during the three months ended March 31, 2012 which increased realized average gas prices from $6.49 for the three months ended March 31, 2011 to $9.83 for the three months ended March 31, 2012.

Oil revenues (exclusive of derivatives) increased $4.9 million or 21% due to an increase in oil volumes of 28,327 barrels or 12%. The average oil price of $110.11 for the three months ended March 31, 2012 increased by 8% over the average oil price of $102.10 for the three months ended March 31, 2011. Oil revenues (including realized revenues from derivative activities) increased by $3.1 million or 14% due to oil prices which increased by 1% from an average price of $98.02 for the three months ended March 31, 2011 to $99.28 for the three months ended March 31, 2012. Realized losses on oil derivatives, net increased by 199% or $1.8 million from a loss of $1.0 million for the three months ended March 31, 2011 to a loss of $2.8 million for the three months ended March 31, 2012.

Unrealized gain or loss on oil and natural gas derivative contracts was a loss of $20.6 million for the three months ended March 31, 2012 as compared to a loss of $11.3 million for the three months ended March 31, 2011. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding derivative contracts during these periods.

Operating costs and expenses

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

Production taxes. Production taxes were $2.4 million for the three months ended March 31, 2012, and $1.9 million for the comparable period in 2011. The Company pays production taxes to state governments at rates specified by geographic location and commodity. The increase in production taxes is due to the increase in oil and gas sales between periods.

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

Depreciation, depletion and amortization expenses. Depreciation, depletion and amortization expenses for the three months ended March 31, 2012 increased to $19.1 million from $17.0 million for the three months ended March 31, 2011. The increase in depreciation, depletion and amortization was primarily due to a larger net oil and gas property cost base at March 31, 2012.

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

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

Income tax provision. For the three months ended March 31, 2012, the Company recorded income tax expense of $3.4 million as compared to an income tax benefit of $1.6 million for the three months ended March 31, 2011. Income tax expense recognized was based on an effective tax rate calculation of approximately 39.4% at March 31,

2012 and approximately 91.2% at March 31, 2011. The three months’ effective tax rates have been impacted by the deferred tax portion of certain non-cash items corrected in the restatement process and the resulting change in pre-tax income (loss) for these periods. Restated effective tax rates for the years ended December 31, 2012 and 2011 as disclosed in the Company’s Amendment No. 1 of Form 10-K/A for the fiscal year ended December 31, 2012 are 40.9% and 40.5%, respectively. See Item 1, Note 12, Restatement of Previously Issued Financial Statements for further information on the restatement. The difference in the rates for the first quarters of 2012 and 2011, exclusive of all restatement items, was primarily due to a change in the expected annual financial results which affected both the federal and state annualized tax rates.

Liquidity and Capital Resources

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

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

Capital Expenditure Budget

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

•

$26 million for geological and geophysical costs;

•

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

•

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

•

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

•

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

•

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

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

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

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

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

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


	Three Months Ended March 31
	2012			2011
*In thousands*
Net cash provided by operating activities	$	33,395		$	24,126
Net cash used in investing activities		(62,826	)		(9,290	)
Net cash used in financing activities		(3,397	)		(2,483	)

Net increase (decrease) in cash and cash equivalents	$	(32,828	)	$	12,353

Cash flows provided by operating activities

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

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

Cash flows used in investing activities

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

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


	Three Months Ended March 31
	2012		2011
Project Area
Federal	$	727	$	2,386
Shallow State Waters		33,959		4,551
Onshore Texas, Louisiana and Mississippi		21,306		14,014
Oklahoma and Mid-Continent		6,042		4,166

Total	$	62,034	$	25,117

Cash flows provided by financing activities

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

Off-Balance Sheet Arrangements

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

Oil and Gas Derivatives

As part of our risk management program, we utilize derivative transactions to reduce the variability in cash flows associated with 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 derivative contracts limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements. In addition, the use of derivative contracts may involve basis risk. The use of derivative contracts also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. All of our derivative contracts are settled based upon reported settlement prices on the NYMEX. None of our derivative contracts have been designated as cash flow hedges.

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

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


	NYMEX Contract Price
	Total Futures				Total Options
	Volume in Bbls/Mo		Weighted Average Fixed Price		Volume in Bbls/Mo		Weighted Average Strike Price
Period
2012⁽¹⁾		56,850	$	91.68		47,438	$	77.03
2013		27,058	$	88.52		34,584	$	91.14
2014⁽²⁾		17,433	$	85.55		—	$	—

⁽¹⁾	Average volume is calculated for the remainder of the 2012 year.

⁽²⁾	The Company currently does not have any derivative transactions covering volumes in the fourth quarter of 2014. The calculation of average volumes is for the full year of 2014.

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


	NYMEX Contract Price
	Total Futures
	Volume in Mbtu/Mo		Weighted Average Fixed Price
Period
2012⁽¹⁾		1,181,233	$	3.08
2013		644,950	$	3.76
2014		481,517	$	3.96
2015		252,475	$	4.74

⁽¹⁾	Average volume is calculated for the remainder of the 2012 year.

Please see Notes to Unaudited Condensed Consolidated Financial Statements–Note 2, Basis of Presentation and Significant Accounting Policies included in Part I, Item 1 for additional discussion regarding the accounting applicable to our derivative program.

Senior Secured Notes

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

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

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

Amended Revolving Credit Facility

On November 29, 2011, the Company’s Revolving Credit Facility was amended. The borrowing base remains $62.5 million which was undrawn at March 31, 2012. The Credit Agreement governing the amended revolving credit facility includes covenants restricting certain of the Company’s financial ratios, including its current ratio and a debt coverage ratio, and a limitation on general and administrative expenses. The covenants also include limitations on borrowings, investments, and distributions. The Company is in compliance with these debt covenants at March 31, 2012. As of May 30, 2013, the Company was not in compliance with a non-financial covenant included within Section 6.2(b) of the Credit Agreement regarding the non-timely filing of its consolidated financial statements. The Company has received a waiver from its lenders through August 15, 2013 with respect to this violation and anticipates the violation will be cured within this period. Accordingly, no reclassification of the outstanding obligation to current was required. The maturity date is July 1, 2015.

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

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

Critical Accounting Policies and Estimates

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

are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements.

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

Recently Issued Accounting Pronouncements

In June 2011, the FASB issued Accounting Standards Update (“ASU”) Number 2011-05, amending Topic 220 – Comprehensive Income, which the Company adopted on January 1, 2012. The ASU modifies alternative presentation standards, eliminating the option for disclosure of the elements of other comprehensive income within the statement of stockholder’s equity. Adoption of this ASU by the Company 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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

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

To partially reduce price risk caused by these market fluctuations, we utilize derivative transactions to reduce the variability in cash flows associated with 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 derivative 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 derivative activities including a list of the commodity derivatives held by the Company, please see Notes to Unaudited Condensed Consolidated Financial Statements — Note 3, Fair Value Measurements and Notes to Unaudited Condensed Consolidated Financial Statements — Note 5, Commodity Derivative Instruments and Derivative Activities included in this report.

Credit Risk

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

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

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. We have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed 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. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective as of March 31, 2012 solely as a result of the material weaknesses identified in Management’s Annual Report on Internal Control over Financial Reporting included in Amendment No. 1 of Form 10-K/A for the fiscal year ended December 31, 2012.

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

PART II. OTHER INFORMATION

Item 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.

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

July 24, 2013	By:	RAAM Global Energy Company

		By: /s/ Jeffrey Craycraft
		Jeffrey Craycraft
		Chief Financial Officer
		(Duly Authorized Officer and Principal Financial Officer)

Exhibit Index


3.1		Certificate of Incorporation of RAAM Global Energy Company, dated November 19, 2003 (incorporated by reference from Exhibit 3.1 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).

3.2		Bylaws of RAAM Global Energy Company (incorporated by reference from Exhibit 3.2 to the Form S-4 filed on March 17, 2011 (File No. 333-172897)).

31.1 *		Certification of Chief Executive Officer Pursuant to Rule 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Amended.

31.2 *		Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Amended.

32.1 **		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

32.2 **		Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

101***		Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Condensed Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011; (ii) our Condensed Consolidated Statements of Operations for the three months ended March 31, 2012 and 2011; (iii) our Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2012 and 2011; and (iv) the notes to our Condensed Consolidated Financial Statements.

*	Filed herewith.

**	Furnished herewith.

***

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

Attached files

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

RAAM Global Energy Co Reports

Also read