RAAM Global Energy Co - FORM 10-Q

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2014

¨	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 ¨ No þ

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of the Securities Exchange Act of 1934. Although not subject to these filing requirements, RAAM Global Energy Company 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.)

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 August 11, 2014, there were 61,433 shares of common stock, $0.01 par value, outstanding.

TABLE OF CONTENTS


	Page
Cautionary Note Regarding Forward-Looking Statements		3
Part I. Financial Information
Item 1. Financial Statements
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		28
Item 3. Quantitative and Qualitative Disclosures About Market Risk		40
Item 4. Controls and Procedures		42

Part II. Other Information
Item 1. Legal Proceedings		42
Item 1A. Risk Factors		43
Item 6. Exhibits		44

SIGNATURES		45

Exhibit Index		46

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “plan,” “foresee,” “should,” “would,” “could” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information, as to the outcome and timing of future events and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Forward-looking statements may include statements that relate to, among other things, our:

•

forward-looking oil and natural gas reserve estimates;

•

future financial and operating performance and results;

•

business and financial strategy and budgets;

•

cash flow and anticipated liquidity;

•

market prices;

•

technology;

•

amount, nature and timing of capital expenditures;

•

drilling of wells and the anticipated results thereof;

•

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

•

competition and government regulations;

•

operating costs and other expenses;

•

cash flow and anticipated liquidity;

•

prospect development;

•

property acquisitions and sales; and

•

plans, forecasts, objectives, expectations and intentions.

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

•

ability to comply with the financial covenants in our debt agreements;

•

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

•

worldwide political and economic conditions.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see Part II, “Item 1A. Risk Factors” and elsewhere in this report, the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2013, and the risk factors described in registration statements filed with the Securities and Exchange Commission (the “SEC”).

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

All subsequent written and oral forward-looking statements attributable to us are expressly qualified in their entirety by the cautionary statements contained or referred to in this section and any other cautionary statements that may accompany such forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this report.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except for share amounts)

(Unaudited)


	June 30,			December 31,
	2014			2013
Assets
Current assets:
Cash and cash equivalents	$	76,930		$	90,858
Accounts receivable, net of $279 and $656 provision for bad debts in 2014 and 2013, respectively		1,041			5,472
Revenues receivable		19,922			19,517
Income taxes receivable		737			507
Deferred tax asset – current portion		5,346			3,938
Prepaid expenses		5,005			3,863
Other current assets		4,596			4,596

Total current assets		113,577			128,751

Oil and gas properties (full-cost method):
Properties being amortized		1,470,551			1,432,310
Properties not subject to amortization		40,879			45,752
Less accumulated depreciation, depletion, and amortization		(1,232,190	)		(1,190,944	)

Net oil and gas properties		279,240			287,118

Other assets:
Other capitalized assets, net		6,924			7,252
Commodity derivatives		15			1,541
Other		722			1,950

Total other assets		7,661			10,743

Total assets	$	400,478		$	426,612

See accompanying notes to the unaudited condensed consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except for share amounts)

(Unaudited)


	June 30,			December 31,
	2014			2013
Liabilities and equity
Current liabilities:
Accounts payable and accrued liabilities	$	15,925		$	28,066
Revenues payable		18,947			17,699
Interest payable—senior secured notes		7,813			7,813
Current taxes payable		14			25
Advances from joint interest partners		377			4,852
Commodity derivatives—current portion		5,370			4,467
Asset retirement obligations—current portion		18,734			14,089
Debt – current portion		4,225			2,626

Total current liabilities		71,405			79,637

Other liabilities:
Commodity derivatives		832			10
Asset retirement obligations		28,435			29,138
Debt		2,371			2,448
Senior secured notes		250,741			251,037
Deferred income taxes		11,695			14,178
Other long-term liabilities		84			149

Total other liabilities		294,158			296,960

Total liabilities		365,563			376,597

Commitments and contingencies (see Note 10)

Equity:
Common stock, $0.01 par value, 380,000 shares authorized, 61,433 and 61,425 outstanding in 2014 and 2013, respectively		63,534			63,521
Treasury stock at cost, 6,873 shares in 2014 and 2013		(8,552	)		(8,552	)
Accumulated deficit		(25,256	)		(7,441	)

Total equity attributable to RAAM Global shareholders		29,726			47,528
Noncontrolling interest		5,189			2,487

Total equity		34,915			50,015

Total liabilities and equity	$	400,478		$	426,612

See accompanying notes to the unaudited condensed consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Revenues:
Gas sales	$	17,560		$	15,806		$	34,435		$	32,492
Oil sales		19,782			22,869			38,769			49,791
Gains (losses) on derivatives, net		(3,920	)		5,726			(8,640	)		(474	)

Total revenues		33,422			44,401			64,564			81,809

Costs and expenses:
Production and delivery costs		6,896			8,252			13,667			15,938
Production taxes		2,137			1,820			4,164			3,910
Workover costs		289			802			2,115			1,458
Depreciation, depletion and amortization		23,387			17,855			41,905			36,181
General and administrative expenses		1,744			4,655			6,436			9,630

Total operating expense		34,453			33,384			68,287			67,117


Income (loss) from operations		(1,031	)		11,017			(3,723	)		14,692

Other income (expenses):
Interest expense, net		(8,198	)		(7,800	)		(15,988	)		(14,549	)
Other, net		96			(25	)		722			(147	)

Total other income (expenses)		(8,102	)		(7,825	)		(15,266	)		(14,696	)

Income (loss) before taxes		(9,133	)		3,192			(18,989	)		(4	)

Income tax provision (benefit)		(2,257	)		1,251			(3,877	)		(26	)

Net income (loss) including noncontrolling interest	$	(6,876	)	$	1,941		$	(15,112	)	$	22


Net income attributable to noncontrolling interest (net of tax)		473			431			746			951

Net income (loss) attributable to RAAM Global	$	(7,349	)	$	1,510		$	(15,858	)	$	(929	)

See accompanying notes to the unaudited condensed consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Six Months Ended June 30,
	2014			2013
Operating activities
Net income (loss) including noncontrolling interest	$	(15,112	)	$	22
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		42,830			37,101
Deferred income taxes		(3,891	)		(76	)
Stock-based compensation expense		12			—
Changes in assets and liabilities:
Accounts and revenues receivable		3,520			1,823
Income tax receivables		(230	)		161
Prepaids and other current assets		(1,142	)		(4,084	)
Change in derivatives, net		3,251			962
Accounts payable and accrued liabilities		(7,023	)		17,768
Revenues payable		1,248			(8,204	)
Interest payable on Senior Secured Notes		—			1,563
Current taxes payable		(11	)		(301	)
Settlements of asset retirement obligations		(1,869	)		(1,472	)
Other long-term liabilities		(64	)		(132	)

Net cash provided by operating activities		21,519			45,131

Investing activities
Change in advances from joint interest partners		(4,476	)		(85	)
Additions to oil and gas properties and equipment		(28,085	)		(77,181	)
Purchase of reserves in place		(4,921	)		—
Proceeds from net sales of oil and gas properties		506			17,320

Net cash used in investing activities		(36,976	)		(59,946	)

Financing activities
Proceeds from borrowings		4,475			6,757
Payments on borrowings		(2,953	)		(53,119	)
Issuance of 12.5% Senior Secured Notes due 2015		—			51,500
Payments of deferred bond costs		—			(1,540	)
Payment of dividends		—			(1,563	)
Other		7			—

Net cash provided by financing activities		1,529			2,035


Decrease in cash and cash equivalents		(13,928	)		(12,780	)
Cash and cash equivalents, beginning of period		90,858			68,671

Cash and cash equivalents, end of period	$	76,930		$	55,891

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

2. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

The accompanying condensed 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 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 accompanying condensed consolidated balance sheet as of December 31, 2013 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, 2013.

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 $2.1 million and $1.6 million for the three months ended June 30, 2014 and 2013, respectively, and $3.5 million and $3.1 million for the six months ended June 30, 2014 and 2013, respectively. The Company capitalized interest of $0.1 million and $0.4 million during the three months ended June 30, 2014 and 2013, respectively, related to significant active properties not subject to amortization. The Company capitalized interest of $0.6 million and $0.8 million during the six months ended June 30, 2014 and 2013, respectively, related to significant active properties not subject to amortization.

All capitalized costs of oil and gas properties are amortized through depreciation, depletion and amortization (“DD&A”) using the future gross revenue method whereby the annual provision is computed by dividing revenue earned during the period by future gross revenues at the beginning of the period, and applying the resulting rate to 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 $40.9 million and $45.8 million at June 30, 2014 and December 31, 2013, respectively. The Company believes that the unevaluated properties at June 30, 2014 will be substantially evaluated during the remainder of 2014, 2015 and 2016, and the costs will begin to be amortized at that time.

Each quarter, the Company reviews the carrying value of the capitalized oil and gas properties under the full cost accounting guidance of the SEC. This review is referred to as a “ceiling test.” Capitalized costs, less accumulated amortization and related deferred income taxes, shall not exceed an amount equal to the sum of the estimated present value of future net cash flows from proved reserves discounted at 10%, less estimated future expenditures to be incurred in developing and producing the proved reserves based on current economic and operating conditions, plus the lower of cost or fair value of unproved properties, each after income tax effects. To calculate estimated future net revenues, current prices are calculated using the average of the first-day-of-the-month price for the trailing 12-month period.

At June 30, 2014, the Company’s ceiling test computation resulted in a $5.3 million write-down and was based on twelve-month average prices of $96.75 per barrel of oil plus adjustments by lease for quality, transportation fees, and regional price differentials and $4.10 per MMBtu of natural gas plus adjustments by lease for energy content, transportation fees, and regional price differentials. The Company’s ceiling test computation for the fourth quarter of 2013 resulted in a $59.1 million write-down and was based on twelve-month average prices of $93.42 per barrel of oil, plus adjustments by lease for quality, transportation fees, and regional price differentials and $3.67 per MMBtu of natural gas, plus adjustments by lease for energy content, transportation fees, and regional price differentials. The Company’s ceiling test computation for the third quarter of 2013 resulted in a $276.9 million write-down and was based on twelve-month average prices of $91.69 per barrel of oil, plus adjustments by lease for quality, transportation fees, and regional price differentials and $3.61 per MMBtu of natural gas, plus adjustments by lease for energy content, transportation fees, and regional price differentials.

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 first quarter of 2013, the Company sold a 50% working interest in undeveloped acreage onshore Texas to an unrelated third party for $17.3 million. The Company also received a $17.3 million net carry from this unrelated third party. The sale was recorded as a reduction to our net oil and gas properties on the accompanying condensed consolidated balance sheet, with no income statement impact because the sale did not significantly alter the relationship between capitalized costs and proved reserves.

During the second quarter of 2014, the Company purchased working interests in 19 wells located onshore Texas that represented 0.5 MBOE of reserves from a related party entity for a net purchase price of $4.9 million. The Company obtained a reserve report from independent reserve engineers prior to completing the transaction. The purchase was approved by the Company’s Board of Directors. The Company considers pro-forma information related to the purchase of these reserves to be nominal.

During the second quarter of 2014, the Company entered into an agreement to purchase all of the issued and outstanding equity of Charter V, Inc. (“Charter V”) from the shareholders (the “Sellers”) of Charter V for a net purchase price of approximately $5.9 million. The aggregate consideration was based upon a Charter V reserve report and fair market valuation report from a third party. Charter V held reserves totaling 0.4 MBOE. The Sellers consist of 46 individuals who were employees of the Company and Century Exploration New Orleans, Inc., a subsidiary of the Company, as of December 31, 2010. Among these individuals are Howard A. Settle, Chief Executive Officer and a Director of the Company, Jeff T. Craycraft, Chief Financial Officer, and Michael J. Willis, Senior Vice President and a Director of the Company. Charter V is a variable interest entity (“VIE”) of the Company and is accounted for as a non-controlling interest. The Company completed the purchase on July 2, 2014. In the third quarter of 2014, this transaction will be recorded as reductions in both non-controlling interest and cash.

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 condensed consolidated 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 changes in fair value in Gains (losses) on derivatives, net in the accompanying condensed consolidated statements of operations. All realized cash settlements of derivative activities are also recorded in Gains (losses) on derivatives, net in the accompanying condensed consolidated statements of operations. See Note 5, Commodity Derivative Instruments and Derivative Activities included elsewhere in this quarterly report for further details.

Asset Retirement Obligations

In accordance with the provisions of Financial Accounting Standards Board (“FASB”) guidance related to accounting for asset retirement obligations (“ARO”) and FASB guidance on accounting for conditional asset retirement obligations, costs associated with the retirement of fixed assets (e.g., oil and gas production facilities, etc.) that the Company is legally obligated to incur are accrued. The fair value of the obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The Company reassesses its ARO on a quarterly basis and records necessary increases or decreases as changes in estimates in the respective quarter. The Company evaluates whether there are any indicators that suggest that the expected cash flows underlying the ARO liability have changed materially.

The associated asset retirement costs are capitalized as part of the carrying amount of the fixed asset and are depreciated over the life of the applicable asset. 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 in the accompanying condensed consolidated statements of operations.

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


*In thousands*
Balance of ARO as of January 1, 2014	$	43,227
Accretion expense		693
Additions		290
Settlement of ARO		(1,869	)
Changes in ARO estimate		4,828

Balance of ARO as of June 30, 2014	$	47,169

The change in ARO estimates during the second quarter of 2014 was due to new information the Company received through quotes from third parties in regard to performing plugging and abandonment work on some of the Company’s properties located in Federal waters.

Operating Segments

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

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 June 30, 2014 and December 31, 2013, 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).

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:


	Fair Value Measurements Using
*In Thousands*	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Fair Value			Netting⁽¹⁾			Carrying Amount
June 30, 2014
Assets:
Commodity derivatives	$	—	$	626		$	—	$	626		$	(611	)	$	15
Liabilities:
Commodity derivatives		—		(6,813	)		—		(6,813	)		611			(6,202	)
December 31, 2013
Assets:
Commodity derivatives	$	—	$	3,735		$	—	$	3,735		$	(2,194	)	$	1,541
Liabilities:
Commodity derivatives		—		(6,671	)		—		(6,671	)		2,194			(4,477	)

⁽¹⁾	The derivative fair values are based on analysis of each contract on a gross basis, even where the legal right of offset exists.

The Company accounts for derivative instruments in accordance with FASB guidance and all derivative instruments are reflected as either assets or liabilities at fair value on the accompanying condensed consolidated balance sheets. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The fair market value of the Company’s derivative assets and liabilities and their locations on the accompanying condensed consolidated balance sheets are as follows:


	Fair Value Measurements Using Significant Other Observable Inputs (Level 2)
*Description*	June 30, 2014			December 31, 2013
*In thousands*
Assets:
Fair value of commodity derivatives—current assets	$	—		$	—
Fair value of commodity derivatives—long-term assets		15			1,541

Total Assets	$	15		$	1,541


Liabilities:
Fair value of commodity derivatives—current liabilities	$	(5,370	)	$	(4,467	)
Fair value of commodity derivatives—long-term liabilities		(832	)		(10	)

Total Liabilities	$	(6,202	)	$	(4,477	)

During September 2010, July 2011 and April 2013, the Company issued senior secured notes (the “Notes”). At June 30, 2014, the fair value of the Notes was estimated to be approximately $240.0 million, based on the prices the bonds have recently been quoted at in the market, which represent Level 2 inputs. As of June 30, 2014, a total of $250.0 million notional amount of the Notes was outstanding. The carrying amount of the Notes including unamortized premium and discount was $250.7 million as of June 30, 2014.

At December 31, 2013, the fair value of the Notes was estimated to be approximately $259.1 million, based on the prices the bonds have recently been quoted at in the market, which represent Level 2 inputs. As of December 31, 2013, a total of $250.0 million notional amount of the Notes was outstanding. The carrying amount of the Notes was $251.0 million as of December 31, 2013. See Note 6, Debt for further information.

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

4. Accounts and Revenues Receivable

Accounts and revenues receivable at June 30, 2014 and December 31, 2013 were $21.0 million and $25.0 million, respectively, all of which were due from companies in the oil and gas industry. Since all of RAAM Global’s accounts receivable from purchasers and joint interest owners at June 30, 2014 and December 31, 2013 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 June 30, 2014 and December 31, 2013. 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. See Note 2, “Basis of Presentation and Significant Accounting Policies” for additional information on the Company’s derivative activities.

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


Remaining Contract Term	Contract Type	Volume in MMBtus/ Month		NYMEX Strike Price
July 2014—December 2014	Swap		153,333	$	3.67
July 2014—December 2014	Swap		71,667	$	4.15
July 2014—December 2014	Swap		148,167	$	4.00
July 2014—December 2014	Swap		67,606	$	3.98
July 2014—December 2014	Call—Sell		312,800	$	5.00
July 2014—December 2014	Call—Buy		312,800	$	4.50
July 2014—December 2014	Swap		66,193	$	4.25
July 2014—October 2014	Swap		93,314	$	4.55
January 2015—December 2015	Swap		63,955	$	4.18
January 2015—December 2015	Swap		85,433	$	4.35
January 2015—December 2015	Put—Sell		316,430	$	3.50

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


Remaining Contract Term	Contract Type	Volume in BBls/ Month		NYMEX Strike Price
July 2014—September 2014	Put—Sell		21,467	$	63.60
July 2014—December 2014	Swap		18,604	$	92.10
July 2014—September 2014	Swap		21,467	$	85.90
July 2014—September 2014	Swap		3,333	$	95.10
October 2014—December 2014	Swap		3,261	$	92.90
January 2015—December 2015	Swap		20,945	$	89.00
January 2015—December 2015	Put—Sell		20,945	$	70.00

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

6. Debt

2015 Senior Secured Notes

On September 24, 2010, the Company completed an offering of $150.0 million senior secured notes at a coupon rate of 12.5% (the “Original Notes”) with a maturity date of October 1, 2015. Interest on the Original Notes is payable in cash semi-annually in arrears on April 1 and October 1 of each year, which commenced on April 1, 2011, to holders of record at the close of business on the preceding March 15 or September 15. Interest on the Original Notes is computed on the basis of a 360-day year of twelve 30-day months. The Original Notes were sold at 99.086% of their face amount and were recorded at their discounted amount, with the discount to be amortized over the life of the notes. The Company used a portion of the net proceeds from the offering to repay all outstanding indebtedness under the Amended Revolving Credit Facility (as defined below) and the remainder of the proceeds were 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 “Existing 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.

On April 11, 2013, the Company completed the issuance and sale of $50.0 million aggregate principal amount of additional 12.5% Senior Notes due 2015 (the “New Additional Notes,” collectively with the Original Notes and the Additional Notes, the “Notes”). The New Additional Notes are additional notes permitted under the indenture dated as of September 24, 2010, pursuant to which the Company initially issued the Original and Additional Notes, as supplemented by the First Supplemental Indenture dated as of July 15, 2011 (the “First Supplemental Indenture”), the Second Supplemental Indenture dated as of April 11, 2013 (the “Second Supplemental Indenture”) and the Third Supplemental Indenture dated as of April 11, 2013 (the “Third Supplemental Indenture,” and together with the Base Indenture, First Supplemental Indenture and the Second Supplemental Indenture, the “Indenture”).

The New Additional Notes have identical terms, other than the issue date and issue price, and constitute part of the same series as the Original and Additional Notes. The New Additional Notes were sold at 103.0% of their face amount and were recorded at their premium amount, with the premium to be amortized over the life of the notes. The Company received net proceeds from the issuance and sale of the New Additional Notes of approximately $50.3 million, after underwriting fees and estimated offering expenses. The Company used the net proceeds from the offering to repay existing indebtedness under the Company’s amended revolving credit facility and for general corporate purposes. On November 5, 2013, the Company closed an exchange offer registering all of the New Additional Notes.

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 existing and future domestic subsidiaries’ (other than certain future unrestricted subsidiaries’) assets to the extent they constitute collateral under our Amended Revolving Credit Facility, subject to certain exceptions. Pursuant to an Intercreditor Agreement, the lien securing the Notes is subordinated and junior to liens securing our Amended Revolving Credit Facility.

Amended Revolving Credit Facility

The Company’s Fourth Amended and Restated Credit Agreement, as amended (the “Amended Revolving Credit Facility”) has a maturity date of July 1, 2015. The borrowing base was $50.0 million of which zero was drawn at June 30, 2014 and at December 31, 2013. The Credit Agreement governing the Amended Revolving Credit Facility includes covenants restricting certain of the Company’s financial ratios, including its current ratio and an interest coverage ratio, and a limitation on general and administrative expenses. The covenants also include limitations on borrowings, investments and distributions. The Company was in compliance with these debt covenants at June 30, 2014, with the exception of the interest coverage ratio. The covenant specifies that the Company should maintain at least a 2.5 to 1.0 interest coverage ratio for the four immediately preceding consecutive fiscal quarters. For the four immediately preceding fiscal quarters ended June 30, 2014, the Company’s interest coverage ratio was 2.3 to 1.0. The Company did not meet this covenant for the four immediately preceding fiscal quarters ended June 30, 2014 due to increased debt balances at a higher average interest rate than during previous periods combined with lower revenues mainly due to decreased oil production and lower oil prices. This covenant breach is an event of default under the credit facility.

As a result of this covenant breach, on July 31, 2014 the Company entered into a forbearance agreement with its senior secured lenders under the Amended Revolving Credit Facility (the “Forbearance Agreement”). Pursuant to the Forbearance Agreement, the lenders, as well as the counterparties to certain outstanding hedging agreements with the Company, have agreed to forbear from exercising any rights or remedies that any of them may have, or from initiating or instituting legal proceedings, against the Company or any of the subsidiary guarantors under the Amended Revolving Credit Facility, or from realizing on their security granted in connection with the Credit Agreement, until the earlier of September 30, 2014 or the occurrence of an event of default within the meaning of the Forbearance Agreement. Pursuant to the terms of the Forbearance Agreement, among other provisions, the borrowing base was permanently reduced to zero, thereby preventing additional borrowings under the Amended Revolving Credit Facility. The Company also agreed to maintain $4.0 million in deposit accounts with the administrative agent in connection with the settlement of the outstanding hedging agreements.

Promissory Note

The Company has a promissory note related to the construction of the Houston office building. The balance was approximately $2.5 million at June 30, 2014 and $2.6 million at December 31, 2013. The note requires monthly installments of principal and interest in the amount of approximately $27,000 until September 1, 2025. There are no covenant requirements under this promissory note.

Finance Agreement

During May 2014, the Company entered into an agreement to finance the premiums for its annual insurance policies. At June 30, 2014, $4.1 million was outstanding under this agreement. The finance agreement required monthly installments of principal and interest in the amount of approximately $0.4 million until April 1, 2015. There are no covenant requirements under this agreement.

7. Income Taxes

Income tax benefit for the three months ended June 30, 2014 was $2.3 million or an effective tax rate of 24.7% compared to an income tax expense of $1.3 million or an effective tax rate of 39.2% for the three months ended June 30, 2013. Income tax benefit for the six months ended June 30, 2014 was $3.9 million or an effective tax rate of 20.4% compared to an income tax benefit of $26,000 or an effective tax rate of 648.0% for the six months ended June 30, 2013. The Company’s effective income tax rate for the three and six months ended June 30, 2014 differed from the federal statutory rate of 35.0% primarily because of state and local income taxes, percentage depletion in excess of cost basis, valuation allowance against deferred tax assets and certain other permanent differences. The Company’s effective income tax rate for the three and six months ended June 30, 2013 differed from the federal statutory rate of 35.0% primarily because of state and local income taxes, percentage depletion in excess of cost basis, the domestic production activities deduction and certain other permanent differences.

8. Shareholders’ Equity

During the six months ended June 30, 2014, no dividends were paid. During the six months ended June 30, 2013, dividends were paid at $25.00 per share to shareholders of record effective March 15, 2013.

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 $0.2 million and $1.1 million at June 30, 2014 and December 31, 2013, respectively, are included in Accounts receivable on the Company’s condensed consolidated balance sheets and represent joint interest owner receivables. Amounts due to such related parties of $1.8 million and $2.0 million at June 30, 2014 and December 31, 2013, respectively, are included in Revenues payable on the Company’s condensed consolidated balance sheets and represent revenue owner payables.

During the second quarter of 2014, the Company purchased working interests in 19 wells located onshore Texas that represented 0.5 MBOE of reserves from a related party entity for $4.9 million. The Company obtained a reserve report from independent reserve engineers prior to completing the transaction. The purchase was approved by the Company’s Board of Directors.

10. Commitments and Contingencies

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

11. Condensed Consolidating Financial Information

The following condensed consolidating financial information is presented in accordance with SEC Regulation S-X requirements relating to multiple subsidiary guarantors of securities issued by the parent company of those subsidiaries. Each of RAAM Global’s 100%-owned subsidiaries are guarantors of the Notes described in Note 6, “Debt.” The guarantees are full and unconditional and joint and several.

The following tables present condensed consolidating balance sheets as of June 30, 2014 and December 31, 2013, condensed consolidating statements of operations for the three and six months ended June 30, 2014 and 2013, and condensed consolidating statements of cash flows for the six months ended June 30, 2014 and 2013, and should be read in conjunction with the condensed consolidated financial statements herein.

Condensed Consolidating Balance Sheets

At June 30, 2014 (in thousands)


	RAAM Global Energy Company		Subsidiary Guarantors		Non-guarantor VIEs		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	670	$	76,194	$	66	$	—		$	76,930
Receivables, net		737		27,581		911		(7,529	)		21,700
Deferred tax asset—current		—		5,346		—		—			5,346
Prepaids and other current assets		2,447		7,154		—		—			9,601

Total current assets		3,854		116,275		977		(7,529	)		113,577

Net oil and gas properties		—		268,437		10,803		—			279,240

Total other assets		295,565		922		—		(288,826	)		7,661

Total assets	$	299,419	$	385,634	$	11,780	$	(296,355	)	$	400,478

Liabilities and equity
Current liabilities:
Payables and accrued liabilities	$	9,191	$	34,402	$	6,635	$	(7,529	)	$	42,699
Advances from joint interest partners		—		377		—		—			377
Commodity derivatives—current portion		—		5,370		—		—			5,370
Asset retirement obligations—current portion		—		18,734		—		—			18,734
Long-term debt—current portion		152		4,073		—		—			4,225

Total current liabilities		9,343		62,956		6,635		(7,529	)		71,405
Other liabilities:
Commodity derivatives		—		832		—		—			832
Asset retirement obligations		—		28,230		205		—			28,435
Long-term debt		2,371		—		—		—			2,371
Senior secured notes		250,741		—		—		—			250,741
Deferred income taxes		5,198		4,790		1,707		—			11,695
Other long-term liabilities		84		—		—		—			84

Total other liabilities		258,394		33,852		1,912		—			294,158
Total liabilities		267,737		96,808		8,547		(7,529	)		365,563
Equity attributable to RAAM Global shareholders		29,726		288,826		—		(288,826	)		29,726
Noncontrolling interest		1,956		—		3,233		—			5,189

Total equity		31,682		288,826		3,233		(288,826	)		34,915

Total liabilities and equity	$	299,419	$	385,634	$	11,780	$	(296,355	)	$	400,478

Condensed Consolidating Balance Sheets

At December 31, 2013 (in thousands)


	RAAM Global Energy Company		Subsidiary Guarantors		Non-guarantor VIEs		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	628	$	90,225	$	5	$	—		$	90,858
Receivables, net		507		33,124		823		(8,958	)		25,496
Deferred tax asset—current		—		3,938		—		—			3,938
Prepaids and other current assets		2,561		5,898		—		—			8,459

Total current assets		3,696		133,185		828		(8,958	)		128,751

Net oil and gas properties		4,112		271,459		11,547		—			287,118

Total other assets		309,899		1,966		—		(301,122	)		10,743

Total assets	$	317,707	$	406,610	$	12,375	$	(310,080	)	$	426,612

Liabilities and equity
Current liabilities:
Payables and accrued liabilities	$	11,200	$	43,127	$	8,234	$	(8,958	)	$	53,603
Advances from joint interest partners		—		4,852		—		—			4,852
Commodity derivatives—current portion		—		4,467		—		—			4,467
Asset retirement obligations—current portion		—		14,089		—		—			14,089
Long-term debt — current portion		147		2,479		—		—			2,626

Total current liabilities		11,347		69,014		8,234		(8,958	)		79,637
Other liabilities:
Commodity derivatives		—		10		—		—			10
Asset retirement obligations		—		28,941		197		—			29,138
Long-term debt		2,448		—		—		—			2,448
Senior secured notes		251,037		—		—		—			251,037
Deferred income taxes		5,198		7,523		1,457		—			14,178
Other long-term liabilities		149		—		—		—			149

Total other liabilities		258,832		36,474		1,654		—			296,960
Total liabilities		270,179		105,488		9,888		(8,958	)		376,597
Equity attributable to RAAM Global shareholders		47,528		301,122		—		(301,122	)		47,528
Noncontrolling interest		—		—		2,487		—			2,487

Total equity		47,528		301,122		2,487		(301,122	)		50,015

Total liabilities and equity	$	317,707	$	406,610	$	12,375	$	(310,080	)	$	426,612

Condensed Consolidating Statements of Operations

Three Months Ended June 30, 2014 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs		Eliminations			Consolidated
Revenues:
Gas sales	$	—		$	16,611		$	949	$	—		$	17,560
Oil sales		—			19,117			665		—			19,782
Losses on derivatives, net		—			(3,920	)		—		—			(3,920	)

Total revenues		—			31,808			1,614		—			33,422
Costs and expenses:
Production and delivery costs		—			6,843			53		—			6,896
Production taxes		—			2,037			100		—			2,137
Workover costs		—			289			—		—			289
Depreciation, depletion and amortization		(144	)		22,739			792		—			23,387
General and administrative expenses		1,765			(29	)		8		—			1,744

Total operating expense		1,621			31,879			953		—			34,453

Income (loss) from operations		(1,621	)		(71	)		661		—			(1,031	)
Other income (expenses):
Interest expense, net		(8,174	)		(24	)		—		—			(8,198	)
Income from equity investment in subsidiaries		2,439			—			—		(2,439	)		—
Other, net		2			94			—		—			96

Total other income (expenses)		(5,733	)		70			—		(2,439	)		(8,102	)

Income (loss) before taxes		(7,354	)		(1	)		661		(2,439	)		(9,133	)
Income tax (benefit) provision		(5	)		(2,440	)		188		—			(2,257	)

Net income (loss) including noncontrolling interest	$	(7,349	)	$	2,439		$	473	$	(2,439	)		(6,876	)

Net income attributable to noncontrolling interest (net of tax)		—			—			473		—			473

Net income (loss) attributable to RAAM Global	$	(7,349	)	$	2,439		$	—	$	(2,439	)	$	(7,349	)

Condensed Consolidating Statements of Operations

Three Months Ended June 30, 2013 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs		Eliminations			Consolidated
Revenues:
Gas sales	$	—		$	15,033		$	773	$	—		$	15,806
Oil sales		—			22,012			857		—			22,869
Gains on derivatives, net		—			5,726			—		—			5,726

Total revenues		—			42,771			1,630		—			44,401
Costs and expenses:
Production and delivery costs		—			8,139			113		—			8,252
Production taxes		—			1,755			65		—			1,820
Workover costs		—			797			5		—			802
Depreciation, depletion and amortization		189			16,912			754		—			17,855
General and administrative expenses		2,152			2,500			3		—			4,655

Total operating expense		2,341			30,103			940		—			33,384

Income (loss) from operations		(2,341	)		12,668			690		—			11,017
Other income (expenses):
Interest expense, net		(7,719	)		(81	)		—		—			(7,800	)
Income from equity investment in subsidiaries		11,785			—			—		(11,785	)		—
Other, net		8			(33	)		—		—			(25	)

Total other income (expenses)		4,074			(114	)		—		(11,785	)		(7,825	)

Income (loss) before taxes		1,733			12,554			690		(11,785	)		3,192
Income tax (benefit) provision		(208	)		1,200			259		—			1,251

Net income (loss) including noncontrolling interest	$	1,941		$	11,354		$	431	$	(11,785	)	$	1,941

Net income attributable to noncontrolling interest (net of tax)		431			—			—		—			431

Net income (loss) attributable to RAAM Global	$	1,510		$	11,354		$	431	$	(11,785	)	$	1,510

Condensed Consolidating Statements of Operations

Six Months Ended June 30, 2014 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs		Eliminations			Consolidated
Revenues:
Gas sales	$	—		$	32,788		$	1,647	$	—			$ 34,435
Oil sales		—			37,636			1,133		—			38,769
Losses on derivatives, net		—			(8,640	)		—		—			(8,640	)

Total revenues		—			61,784			2,780		—			64,564
Costs and expenses:
Production and delivery costs		—			13,493			174		—			13,667
Production taxes		—			3,992			172		—			4,164
Workover costs		—			2,115			—		—			2,115
Depreciation, depletion and amortization		180			40,305			1,420		—			41,905
General and administrative expenses		4,402			2,026			8		—			6,436

Total operating expense		4,582			61,931			1,774		—			68,287

Income (loss) from operations		(4,582	)		(147	)		1,006		—			(3,723	)
Other income (expenses):
Interest expense, net		(15,939	)		(49	)		—		—			(15,988	)
Income from equity investment in subsidiaries		4,360			—			—		(4,360	)		—
Other, net		307			415			—		—			722

Total other income (expenses)		(11,272	)		366			—		(4,360	)		(15,266	)

Income (loss) before taxes		(15,854	)		219			1,006		(4,360	)		(18,989	)
Income tax (benefit) provision		4			(4,141	)		260		—			(3,877	)

Net income (loss) including noncontrolling interest	$	(15,858	)	$	4,360		$	746	$	(4,360	)		(15,112	)

Net income attributable to noncontrolling interest (net of tax)		—			—			746		—			746

Net income (loss) attributable to RAAM Global	$	(15,858	)	$	4,360		$	—	$	(4,360	)		$(15,858)

Condensed Consolidating Statements of Operations

Six Months Ended June 30, 2013 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs		Eliminations			Consolidated
Revenues:
Gas sales	$	—		$	30,947		$	1,545	$	—		$	32,492
Oil sales		—			47,950			1,841		—			49,791
Losses on derivatives, net		—			(474	)		—		—			(474	)

Total revenues		—			78,423			3,386		—			81,809
Costs and expenses:
Production and delivery costs		—			15,709			229		—			15,938
Production taxes		—			3,776			134		—			3,910
Workover costs		—			1,452			6		—			1,458
Depreciation, depletion and amortization		361			34,330			1,490		—			36,181
General and administrative expenses		3,932			5,694			4		—			9,630

Total operating expense		4,293			60,961			1,863		—			67,117

Income (loss) from operations		(4,293	)		17,462			1,523		—			14,692
Other income (expenses):
Interest expense, net		(14,039	)		(510	)		—		—			(14,549	)
Income from equity investment in subsidiaries		18,543			—			—		(18,543	)		—
Other, net		(150	)		3			—		—			(147	)

Total other income (expenses)		4,354			(507	)		—		(18,543	)		(14,696	)

Income (loss) before taxes		61			16,955			1,523		(18,543	)		(4	)
Income tax provision (benefit)		39			(637	)		572		—			(26	)

Net income (loss) including noncontrolling interest	$	22		$	17,592		$	951	$	(18,543	)	$	22

Net income attributable to noncontrolling interest (net of tax)		951			—			—		—			951

Net income (loss) attributable to RAAM Global	$	(929	)	$	17,592		$	951	$	(18,543	)	$	(929	)

Condensed Consolidating Statements of Cash Flows

Six Months Ended June 30, 2014 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(16,996	)	$	40,465		$	2,410		$	(4,360	)	$	21,519
Investing activities
Change in investments between affiliates		17,115			(19,797	)		(1,678	)		4,360			—
Change in advances from joint interest partners		—			(4,476	)		—			—			(4,476	)
Additions to oil and gas properties and equipment		(5	)		(27,409	)		(671	)		—			(28,085	)
Purchase of reserves in place		—			(4,921	)		—			—			(4,921	)
Proceeds from net sales of oil and gas properties		—			506			—			—			506

Net cash provided by (used in) investing activities		17,110			(56,097	)		(2,349	)		4,360			(36,976	)
Financing activities
Proceeds from borrowings		—			4,475			—			—			4,475
Payments on borrowings		(72	)		(2,881	)		—			—			(2,953	)
Other		—			7			—			—			7

Net cash provided by (used in) financing activities		(72	)		1,601			—			—			1,529

Increase (decrease) in cash and cash equivalents		42			(14,031	)		61			—			(13,928	)
Cash and cash equivalents, beginning of period		628			90,225			5			—			90,858

Cash and cash equivalents, end of period	$	670		$	76,194		$	66		$	—		$	76,930

Condensed Consolidating Statements of Cash Flows

Six Months Ended June 30, 2013 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	2,599		$	58,044		$	3,031		$	(18,543	)	$	45,131
Investing activities
Change in investments between affiliates		(49,164	)		32,499			(1,878	)		18,543			—
Change in advances from joint interest partners		—			(85	)		—			—			(85	)
Additions to oil and gas properties and equipment		(1,751	)		(74,273	)		(1,157	)		—			(77,181	)
Proceeds from net sales of oil and gas properties		—			17,320			—			—			17,320

Net cash (used in) provided by investing activities		(50,915	)		(24,539	)		(3,035	)		18,543			(59,946	)
Financing activities
Proceeds from borrowings		—			6,757			—			—			6,757
Payments on borrowings		(67	)		(53,052	)		—			—			(53,119	)
Issuance of 12.5% Senior Secured Notes due 2015		51,500			—			—			—			51,500
Payments of deferred bond costs		(1,540	)		—			—			—			(1,540	)
Payment of dividends		(1,563	)		—			—			—			(1,563	)

Net cash provided by (used in) financing activities		48,330			(46,295	)		—			—			2,035

Increase (decrease) in cash and cash equivalents		14			(12,790	)		(4	)		—			(12,780	)
Cash and cash equivalents, beginning of period		514			68,148			9			—			68,671

Cash and cash equivalents, end of period	$	528		$	55,358		$	5		$	—		$	55,891

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, 2013. Our operating results for the periods discussed may not be indicative of future performance. The following discussion and analysis includes forward-looking statements and should be read in conjunction with “Risk Factors” under Part II, Item 1A of this report, along with the “Cautionary Note Regarding Forward-Looking Statements” at the beginning of this report and our Annual Report on Form 10-K for the year ended December 31, 2013, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are a privately held oil and natural gas exploration and production company engaged in the exploration, development, production and acquisition of oil and gas properties. Our operations are located in the Gulf of Mexico, offshore Louisiana and onshore Louisiana, Texas, Oklahoma and California. We focus on the development of both conventional and unconventional resource plays.

We are currently focused on evaluating and developing our asset base, optimizing our acreage positions and evaluating potential acquisitions, with an emphasis on the development and acquisition of unconventional plays. We are currently seeking partners for joint venture or farm-out arrangements for certain assets located in the Breton Sound area, Ship Shoal area, the Yegua and Cook Mountain region, and the Mid-Continent region. In our onshore conventional plays, we anticipate drilling two additional wells in our Texas Yegua trend. Also, we are currently pursuing permits for a play in California and anticipate drilling two wells there as soon as permitting is complete. We currently have two unconventional plays under lease. One is located in California, and the other is a Mid-Continent play. We anticipate drilling in each of these plays later this year.

We have developed a business model of conducting a thorough evaluation of numerous plays, including a detailed geological and geophysical review. When a promising prospect is identified, we conduct core analysis and a very detailed petro physical evaluation in order to fully understand the reserve potential, and we develop a complete economic model to establish the expected returns. Once these evaluations are complete, we create a buy outline for purchasing the undeveloped acreage. We then work to secure a joint venture partner to assist us in developing the acreage. In this model, we would ideally recover a significant portion of our initial investment in the acreage through the arrangement with the joint venture partner. We successfully executed this model in the Bend Arch play during 2013. We subsequently decided to sell our remaining interest in that play to pursue other opportunities; however, we believe it demonstrates the successful execution of our business model.

In each of our core areas, we have established a team of experienced geologists and geophysists with extensive experience in the specific area of exploration. We acquired a large library of data including 3-D seismic surveys, well logs, production history, and other relevant data, and we maintain the latest in computer aided exploration hardware and software. Each prospect is subjected to a peer review process, reservoir engineering review, and economic analysis. The combination of having a complete data set, which is evaluated by experienced professionals along with a thorough geological, engineering, and economic review has led to our exploration drilling success. We have employed this system with success in the Gulf of Mexico and onshore in Texas and Louisiana, and we are establishing the same procedures for our Mid-Continent and California unconventional opportunities.

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.

Recent Developments

Financing Updates

The company has hired Moelis & Company to provide financial advisory services regarding the Company’s strategic business plan, including financing alternatives to its existing bank facility.

Drilling Updates

A well drilled in Louisiana state waters under the Company’s farm-out program was completed in August 2014 and is anticipated to be hooked up and producing by mid-September 2014. The next well in the farm-out program is scheduled to be spud by the end of the third quarter. One of our California wells, which was spud on August 6, 2014, is expected to reach total depth by the end of the third quarter of 2014. A rig has been contracted to drill a well in the Texas Yegua trend and is scheduled to be on location by the end of August 2014. The Company also has another rig contracted to begin drilling in the Texas Yegua trend in early September.

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 and six month periods ended June 30, 2014 and 2013.


	Three Months Ended June 30,					Six Months Ended June 30,
	2014			2013		2014			2013
Average daily production:
Oil (Bbl per day)		2,084			2,350		2,097			2,560
Natural gas (Mcf per day)		37,115			38,205		36,153			42,065
Oil equivalents (Boe per day)		8,270			8,718		8,122			9,571

Average prices:⁽¹⁾
Oil ($/Bbl)	$	104.29		$	106.94	$	102.16		$	107.46
Natural gas ($/Mcf)	$	5.20		$	4.55	$	5.26		$	4.27
Oil equivalents ($/Boe)	$	49.62		$	48.75	$	49.79		$	47.50

Production and delivery costs ($/Boe)	$	9.16		$	10.40	$	9.30		$	9.20
General and administrative expenses ($/Boe)	$	2.32		$	5.89	$	4.38		$	5.56
Net income (loss) attributable to RAAM Global (in thousands)	$	(7,349	)	$	1,510	$	(15,858	)	$	(929	)
Adjusted EBITDA ⁽²⁾ (in thousands)	$	23,901		$	21,220	$	41,460		$	50,775

⁽¹⁾	Average prices presented do not give effect to our derivative activities or the monetization of oil derivatives during February 2013. Please see Item 1, 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 net losses (gains) on derivatives, net of cash settlements received or paid, interest expense, income taxes, depreciation, depletion and amortization. We consider Adjusted EBITDA to be an important indicator for the performance of our business, but not a measure of performance calculated in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”).

We have included this non-GAAP financial measure because management utilizes this information for assessing our performance and liquidity and as an indicator of our ability to make capital expenditures, service debt and finance working capital requirements. Management believes that Adjusted EBITDA is a measurement that is commonly used by analysts and some investors in evaluating the performance and liquidity of companies in our industry. In particular, we believe that it is useful to our analysts and investors to understand this relationship because it excludes noncash expense items, such as depletion. We believe that excluding these transactions allows investors to meaningfully trend and analyze the performance and liquidity of our core cash operations. Adjusted EBITDA should not be considered as an alternative to net income, operating income or any other performance measure derived in accordance with U.S. GAAP or as an alternative to net cash provided by operating activities as a measure of our profitability or liquidity. 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 (loss) as determined in accordance with U.S. GAAP, the most comparable U.S. GAAP measure, to Adjusted EBITDA for the three and six month periods ended June 30, 2014 and 2013.


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
*In thousands*
Net income (loss) attributable to RAAM Global	$	(7,349	)	$	1,510		$	(15,858	)	$	(929	)
Net losses (gains) on derivatives, net of cash settlements received or paid		1,897			(7,218	)		3,251			962
Interest expense		8,223			7,822			16,039			14,587
Depreciation, depletion and amortization		23,387			17,855			41,905			36,181
Income taxes		(2,257	)		1,251			(3,877	)		(26	)

Adjusted EBITDA	$	23,901		$	21,220		$	41,460		$	50,775

Results of Operations

The following table sets forth the unaudited results of operations for the three and six month periods ended June 30, 2014 and 2013 in thousands.


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
Revenues:
Gas sales	$	17,560		$	15,806		$	34,435		$	32,492
Oil sales		19,782			22,869			38,769			49,791
Gains (losses) on derivatives, net		(3,920	)		5,726			(8,640	)		(474	)

Total revenues		33,422			44,401			64,564			81,809
Costs and expenses:
Production and delivery costs		6,896			8,252			13,667			15,938
Production taxes		2,137			1,820			4,164			3,910
Workover costs		289			802			2,115			1,458
Depreciation, depletion and amortization		23,387			17,855			41,905			36,181
General and administrative expenses		1,744			4,655			6,436			9,630

Total operating expense		34,453			33,384			68,287			67,117

Income (loss) from operations		(1,031	)		11,017			(3,723	)		14,692
Other income (expenses):
Interest expense, net		(8,198	)		(7,800	)		(15,988	)		(14,549	)
Other, net		96			(25	)		722			(147	)

Total other income (expenses)		(8,102	)		(7,825	)		(15,266	)		(14,696	)

Income (loss) before taxes		(9,133	)		3,192			(18,989	)		(4	)
Income tax provision (benefit)		(2,257	)		1,251			(3,877	)		(26	)

Net income (loss) including noncontrolling interest	$	(6,876	)	$	1,941		$	(15,112	)	$	22

Net income attributable to noncontrolling interest (net of tax)		473			431			746			951

Net income (loss) attributable to RAAM Global	$	(7,349	)	$	1,510		$	(15,858	)	$	(929	)

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

Revenues

Oil and natural gas production. Oil and natural gas production for the three months ended June 30, 2014 decreased to 0.75 MMBoe from 0.79 MMBoe for the three months ended June 30, 2013. During the three months ended June 30, 2014, natural gas production decreased 3% and oil production decreased 11%, resulting in a 5% decrease in Boe production over the three months ended June 30, 2014. Oil and natural gas production decreased because production from new wells and recompletions in both the shallow waters of Louisiana and onshore Texas did not offset normal production declines from our mature wells and production declines due to the formation collapse that led to the shearing of the casing in several of our Texas wells in late second quarter of 2013.

Total revenues. Total revenues for the three months ended June 30, 2014 decreased to $33.4 million from $44.4 million for the three months ended June 30, 2013. Natural gas revenues (exclusive of derivatives) increased $1.8 million or 11% due to higher natural gas prices along with higher production for the three months ended June 30, 2014 as compared to the three months ended June 30, 2013. Natural gas prices increased by 14% period over period, to an average price of $5.20 for the three months ended June 30, 2014 from an average natural gas price of $4.55 for the three months ended June 30, 2013.

Oil revenues (exclusive of derivatives) decreased $3.1 million or 13%, over the prior year period due to lower oil volumes and lower oil prices. The average oil price of $104.29 for the three months ended June 30, 2014 represented 2% decrease from the average oil price of $106.94 for the three months ended June 30, 2013 (excluding the effects of derivative activities).

Operating costs and expenses

Production and delivery costs. Production and delivery costs for the three months ended June 30, 2014 decreased to $6.9 million from $8.3 million for the same period in 2013. Production and delivery costs per Boe decreased to $9.16 per Boe for the three months ended June 30, 2014 from $10.40 per Boe for the same period in 2013 primarily as a result of lower production and delivery costs during the second quarter of 2014. In the second quarter of 2014 the Company experienced lower contract pumping services and insurance and labor costs than those during the same period in 2013.

Production taxes. Production taxes were $2.1 million for the three months ended June 30, 2014, and $1.8 million for the comparable period in 2013. The Company pays production taxes to state governments at rates specified by geographic location and commodity. The slight increase in production taxes is due primarily to a new onshore well coming online during the quarter.

Workover costs. Our workover costs for the three months ended June 30, 2014 decreased to $0.3 million from $0.8 million for the same period in 2013. Workover costs per Boe decreased to $0.38 for the three months ended June 30, 2014 from $1.01 per Boe for the same period in 2013 primarily as a result of decreased workover costs during the second quarter of 2014. Workovers are performed on wells that need certain mechanical changes or enhancements to maintain or increase production. Due to less mechanical needs during the second quarter of 2014, the Company performed less workovers in that period than were necessary during the same period in 2013. Also, workover projects performed during the second quarter of 2014 had lower equipment rental and electric line service costs than those performed during the same period of 2013.

Depreciation, depletion and amortization. Depreciation, depletion and amortization for the three months ended June 30, 2014 increased to $23.4 million from $17.9 million for the three months ended June 30, 2013. The depletion rate for the second quarter of 2014 was higher than the depletion rate for the same period in 2013 due to lower future gross revenues at June 30, 2014 resulting from the downward revisions to eliminate the Ewing Banks 920 Project proved undeveloped reserves during the third quarter of 2013. Also, a $5.3 million ceiling test writedown was recorded at June 30, 2014.

General and administrative expenses. General and administrative expenses decreased to $1.7 million for the three months ended June 30, 2014 from $4.7 million for the three months ended June 30, 2013. The decrease in general and administrative expenses was mainly due to lower consultant compensation, data processing and repairs and maintenance costs during the second quarter of 2014 as compared to the same period of 2013.

Interest expense, net. Net interest expense increased to $8.2 million for the three months ended June 30, 2014, from $7.8 million for the three months ended June 30, 2013 because of higher average interest rates. Debt balances averaged $250.0 million during the three months ended June 30, 2014 and 2013. Interest rates averaged 12.5% and 11.9% during the three months ended June 30, 2014 and 2013, respectively. In the second quarter of 2014, the Company had $250.0 million of senior secured notes outstanding with a 12.5% interest rate. For a portion of the second quarter of 2013, the Company had $200.0 million of senior secured notes outstanding with a 12.5% interest rate and $50.0 million outstanding under the amended revolving credit facility with an average interest rate of 3.2%.

Income tax (benefit) provision. For the three months ended June 30, 2014, the Company recorded an income tax benefit of $2.3 million as compared to income tax expense of $1.3 million for the three months ended June 30, 2013. Income tax (benefit) provision recognized was based on effective tax rate calculations of approximately 24.7% at June 30, 2014 and approximately 39.2% at June 30, 2013. The difference in the rates for the second quarters of 2014 and 2013 is primarily due to the recording of a valuation allowance against deferred tax assets in 2014. The valuation allowance is recorded based on our current assessment that it is more likely than not that certain of our deferred tax assets will not be realized in the foreseeable future.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Revenues

Oil and natural gas production. Oil and natural gas production for the six months ended June 30, 2014 decreased to 1.5 MMBoe from 1.7 MMBoe for the six months ended June 30, 2013. During the six months ended June 30, 2014, natural gas production decreased 14% and oil production decreased 18%, resulting in a 15% decrease in Boe production over the six months ended June 30, 2013. Oil and natural gas production decreased because production from new wells and recompletions in both the shallow waters of Louisiana and onshore Texas did not offset normal production declines from our mature wells and production declines due to the formation collapse that led to the shearing of the casing in several of our Texas wells in late second quarter of 2013.

Total revenues. Total revenues for the six months ended June 30, 2014 decreased to $64.6 million from $81.8 million for the six months ended June 30, 2013. Natural gas revenues (exclusive of derivatives) increased $1.9 million or 6% due to higher natural gas prices more than offsetting lower natural gas production for the six months ended June 30, 2014 as compared to the six months ended June 30, 2013. Natural gas prices increased by 23% period over period, to an average price of $5.26 for the six months ended June 30, 2014 from an average natural gas price of $4.27 for the six months ended June 30, 2013.

Oil revenues (exclusive of derivatives) decreased $11.0 million or 22%, over the prior year period due to lower oil volumes and lower oil prices. The average oil price of $102.16 for the six months ended June 30, 2014 represented a 5% decrease from the average oil price of $107.46 for the six months ended June 30, 2013 (excluding the effects of derivative activities).

Operating costs and expenses

Production and delivery costs. Production and delivery costs for the six months ended June 30, 2014 decreased to $13.7 million from $15.9 million for the same period in 2013. Production and delivery costs per Boe increased to $9.30 per Boe for the six months ended June 30, 2014 from $9.20 per Boe for the same period in 2013 primarily as a result of decreased oil and natural gas production described above in the first half of 2014. During 2014 the Company also experienced lower contract pumping services, insurance, lift boat and labor costs and supplies and tools than those during the same period in 2013.

Production taxes. Production taxes were $4.2 million for the six months ended June 30, 2014, and $3.9 million for the comparable period in 2013. The Company pays production taxes to state governments at rates specified by geographic location and commodity. The slight increase in production taxes is due primarily to a new onshore well coming online during the period.

Workover costs. Our workover costs for the six months ended June 30, 2014 increased to $2.1 million from $1.5 million for the same period in 2013. Workover costs per Boe increased to $1.44 for the six months ended June 30, 2014 from $0.84 per Boe for the same period in 2013 primarily as a result of decreased oil and natural gas production described above in the first half of 2014. Workovers are performed on wells that need certain mechanical changes or enhancements to maintain or increase production.

Due to mechanical needs during the first half of 2014, the Company performed more workovers in that period than were necessary during the same period in 2013. Also, workover projects performed during the first half of 2014 had higher lift boat, contract rig and surface equipment costs than those performed during the same period of 2013.

Depreciation, depletion and amortization. Depreciation, depletion and amortization for the six months ended June 30, 2014 increased to $41.9 million from $36.2 million for the six months ended June 30, 2013. The depletion rates for the first and second quarters of 2014 were higher than the depletion rates for the same periods in 2013 due to lower future gross revenues at both March 31, 2014 and June 30, 2014 resulting from the downward revisions to eliminate the Ewing Banks 920 Project proved undeveloped reserves during the third quarter of 2013. Also, a $5.3 million ceiling test writedown was recorded at June 30, 2014.

General and administrative expenses. General and administrative expenses decreased to $6.4 million for the six months ended June 30, 2014 from $9.6 million for the six months ended June 30, 2013. The decrease in general and administrative expenses was mainly due to lower consultant compensation, data processing and repairs and maintenance costs during the first half of 2014 as compared to the same period of 2013.

Interest expense, net. Net interest expense increased to $16.0 million for the six months ended June 30, 2014, from $14.5 million for the six months ended June 30, 2013 because of higher average interest rates. Debt balances averaged $250.0 million during the six months ended June 30, 2014 and 2013. Interest rates averaged 12.5% and 11.3% during the six months ended June 30, 2014 and 2013, respectively. In the first half of 2014, the Company had $250.0 million of senior secured notes outstanding with a 12.5% interest rate. In the first half of 2013, the Company had $200.0 million of senior secured notes outstanding with a 12.5% interest rate and $50.0 million outstanding under the amended revolving credit facility with an average interest rate of 3.2%.

Income tax benefit. For the six months ended June 30, 2014, the Company recorded an income tax benefit of $3.9 million as compared to an income tax benefit of $26,000 for the six months ended June 30, 2013. Income tax benefits recognized were based on effective tax rate calculations of approximately 20.4% at June 30, 2014 and approximately 648% at June 30, 2013. The difference in the rates for the first six months of 2014 and 2013 is primarily due to a change in the expected annual financial results which affected both the federal and state annualized tax rates and the recording of a valuation allowance against deferred tax assets in 2014. The valuation allowance is recorded based on our current assessment that it is more likely than not that certain of our deferred tax assets will not be realized in the foreseeable future.

Liquidity and Capital Resources

Our primary sources of liquidity to date have been capital contributions from shareholders, borrowings under our Amended Revolving Credit Facility, debt financings, sales of non-core assets 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.

Capital Expenditures

The Company spent approximately $33 million on capital expenditures during the first six months of 2014. We anticipate spending an additional $30 million on capital expenditures during the remainder of 2014. Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Our total 2014 capital expenditure budget is approximately $63 million, of which approximately $33 million was expended in the first six months of 2014. The Company expects the remaining capital budget of $30 million to consist of:

•

$4 million for geological and geophysical costs, including leasing;

•

$2 million for Louisiana state water drilling and development;

•

$13 million for onshore conventional drilling and development;

•

$7 million for California drilling and development; and

•

$4 million for projects in progress; recompletions.

While we have budgeted $30 million for these purposes for the remainder of 2014, 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 2014 capital budget has been funded from our cash flows from operations and proceeds from the sale of other non-core assets. We believe our existing cash balance and cash flows from operations should be sufficient to fund the remainder of our 2014 capital expenditure budget.

As of June 30, 2014, we had no amounts outstanding under our revolving credit facility and $250.0 million in Notes outstanding. Our revolving credit facility was unavailable at June 30, 2014 due to the Company not being in compliance with the interest coverage ratio. The Company was in compliance with the debt covenants for this facility at June 30, 2014, with the exception of the interest coverage ratio. The covenant specifies that the Company should maintain at least a 2.5 to 1.0 interest coverage ratio for the four immediately preceding consecutive fiscal quarters. For the four immediately preceding fiscal quarters ended June 30, 2014, the Company’s interest coverage ratio was 2.3 to 1.0. The Company did not meet this covenant for the four immediately preceding fiscal quarters ended June 30, 2014 due to increased debt balances at a higher average interest rate than during previous periods combined with lower revenues mainly due to decreased oil production and lower oil prices. This covenant breach is an event of default under the credit facility.

The Company is currently working to secure new financing; however, there can be no assurance of additional financing being available or on terms acceptable to us.

Consolidated Cash Flows

The table below discloses the net cash provided by (used in) operating activities, investing activities, and financing activities for the six months ended June 30, 2014 and 2013:


	Six Months Ended June 30,
	2014			2013
*In thousands*
Net cash provided by operating activities	$	21,519		$	45,131
Net cash used in investing activities		(36,976	)		(59,946	)
Net cash provided by financing activities		1,529			2,035

Net decrease in cash and cash equivalents	$	(13,928	)	$	(12,780	)

Cash flows provided by operating activities

Operating activities provided cash totaling $21.5 million during the six months ended June 30, 2014 as compared to cash provided by operating activities of $45.1 million during the six months ended June 30, 2013. The decrease in operating cash flows during the six months ended June 30, 2014 was primarily due to the net loss recorded for the period, the increase in accounts and revenues receivable balances and the decrease in accounts payable balances.

Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and natural 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 commodity prices on our financial position, see Part I, Item 3, “Quantitative and Qualitative Disclosures About Market Risk” below.

Cash flows used in investing activities

Investing activities used cash totaling $37.0 million during the six months ended June 30, 2014 as compared to cash used in investing activities of $60.0 million during the same period in 2013. Cash used in investing activities during the six months ended June 30, 2014 decreased as compared to the same period of 2013 primarily because of decreased drilling onshore Texas as well as the joint venture arrangement for drilling in shallow state waters under which the Company has minor working interests for the drilling phases of projects. Also, proceeds from asset sales occurring in the first six months of 2014 and 2013 generated $0.5 million and $17.3 million, respectively, of additional cash which offset capital expenditures during the periods.

Our capital expenditures for drilling, development and acquisition costs during the six month periods ended June 30, 2014 and 2013 are summarized in the following table (in thousands):


	Six Months Ended June 30,
	2014		2013
Project Area
Federal	$	6,191	$	8,184
Shallow State Waters		3,393		34,983
Onshore Texas, Louisiana and Mississippi		17,847		27,617
California, Oklahoma and Mid-Continent		5,575		6,397

Total	$	33,006	$	77,181

Cash flows provided by financing activities

Financing activities provided cash totaling $1.5 million during the six months ended June 30, 2014 as compared to cash provided by financing activities of $2.0 million during the same period in 2013. Cash flows provided by financing activities during the first six months of 2014 consisted of $4.5 million of borrowings for our insurance premium financing, offset partially by payments of $3.0 million on borrowings. Cash flows provided by financing activities during the first six months of 2013 consisted primarily of a $51.5 million issuance of New Notes and $6.8 million in borrowings for our insurance premium financing offset partially by payments of $53.1 million on our revolving credit facility and other borrowings and $1.6 million for shareholder dividends.

Off-Balance Sheet Arrangements

As of June 30, 2014, 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 natural 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 arrangements limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements. In addition, the use of derivative transactions may involve basis risk. The use of derivative transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. All of our derivative transactions are settled based upon reported settlement prices on the NYMEX.

At June 30, 2014, on a Boe basis, commodity derivative instruments were in place covering approximately 54% of our projected oil and natural gas sales for 2014 and approximately 22% of our projected oil and natural gas sales for 2015. Approximately 54% of the Company’s 2014 natural gas production, approximately 17% of the Company’s 2015 natural gas production, approximately 57% of the Company’s 2014 oil production, and approximately 37% of the Company’s 2015 oil production will yield minimum prices under the contracts as discussed in Item 1, Note 5, “Commodity Derivative Instruments and Derivative Activities.” Future oil and natural gas sales prices on other production will fluctuate according to market conditions.

As of June 30, 2014, the Company had entered into the following oil derivative instruments:


	NYMEX Contract Price
	Swaps
	Volume in Bbls/Mo		Weighted Average Strike Price
Period
2014⁽¹⁾		32,634	$	90.26
2015		20,945	$	89.00

⁽¹⁾	Average volume is calculated for the remainder of the 2014 year.


	NYMEX Contract Price
	Sell Put
	Volume in Bbls/Mo		Weighted Average Strike Price
Period
2014⁽¹⁾		10,733	$	63.60
2015		20,945	$	70.00

⁽¹⁾	Average volume is calculated for the remainder of the 2014 year.

As of June 30, 2014, the Company had entered into the following natural gas derivative instruments:


	NYMEX Contract Price
	Swaps
	Volume in MMBtus/Mo		Weighted Average Strike Price
Period
2014⁽¹⁾		569,175	$	4.02
2015		149,388	$	4.28

⁽¹⁾	Average volume is calculated for the remainder of the 2014 year.


	NYMEX Contract Price
	Sell Call				Buy Call
	Volume in MMBtus/Mo		Weighted Average Strike Price		Volume in MMBtus/Mo		Weighted Average Strike Price
Period
2014⁽¹⁾		312,800	$	5.00		312,800	$	4.50

⁽¹⁾	Average volume is calculated for the remainder of the 2014 year.


	NYMEX Contract Price
	Sell Put
	Volume in MMBtus/Mo		Weighted Average Strike Price
Period
2015		316,430	$	3.50

Please see Item 1, Note 2, “Basis of Presentation and Significant Accounting Policies” included in Part I for additional discussion regarding the accounting applicable to our derivative program.

Financing Facilities

Senior Secured Notes

On September 24, 2010, the Company completed an offering of $150.0 million senior secured notes at a coupon rate of 12.5% (the “Original Notes”) with a maturity date of October 1, 2015. Interest on the Original Notes is payable in cash semi-annually in arrears on April 1 and October 1 of each year, which commenced on April 1, 2011, to holders of record at the close of business on the preceding March 15 or September 15. Interest on the Original Notes is computed on the basis of a 360-day year of twelve 30-day months. The Original Notes were sold at 99.086% of their face amount and were recorded at their discounted amount, with the discount to be amortized over the life of the notes. The Company used a portion of the net proceeds from the offering to repay all outstanding indebtedness under the Amended Revolving Credit Facility and the remainder of the proceeds was used to fund a 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 April 11, 2013, the Company successfully completed the issuance and sale of $50.0 million aggregate principal amount of additional 12.5% Senior Notes due 2015 (the “New Additional Notes,” and together with the Original and Additional Notes, the “Notes”). The New Additional Notes are additional notes issued pursuant to the indenture dated as of September 24, 2010, pursuant to which the Company issued the Original and Additional Notes, as supplemented by the First Supplemental Indenture dated as of July 15, 2011 (the “First Supplemental Indenture”), the Second Supplemental Indenture dated as of April 11, 2013 (the “Second Supplemental Indenture”) and the Third Supplemental Indenture dated as of April 11, 2013 (the “Third Supplemental Indenture,” and together with the Base Indenture, First Supplemental Indenture and the Second Supplemental Indenture, the “Indenture”). The New Additional Notes have identical terms, other than the issue date and issue price, and constitute part of the same series as the Original and Additional Notes. The Company used the net proceeds from the offering to repay existing indebtedness under the Company’s Amended Revolving Credit Facility and for general corporate purposes. On November 5, 2013, the Company closed an exchange offer registering all of the New Additional Notes.

As of June 30, 2014, a total of $250.0 million notional amount of the Notes was outstanding. The carrying amount of the Notes including unamortized premium and discount was $250.7 million as of June 30, 2014.

Amended Revolving Credit Facility

The borrowing base was $50.0 million, and no amounts were drawn at June 30, 2014. Our revolving credit facility was unavailable at June 30, 2014 due to the Company not being in compliance with the interest coverage ratio.

The Credit Agreement governing the Amended Revolving Credit Facility includes covenants restricting certain of the Company’s financial ratios, including its current ratio and a debt coverage ratio, and a limitation on general and administrative expenses. The covenants also include limitations on borrowings, investments and distributions. The Company was in compliance with these debt covenants at June 30, 2014, with the exception of the interest coverage ratio. The covenant specifies that the Company should maintain at least a 2.5 to 1.0 interest coverage ratio for the four immediately preceding consecutive fiscal quarters. For the four immediately preceding fiscal quarters ended June 30, 2014, the Company’s interest coverage ratio was 2.3 to 1.0. The Company did not meet this covenant for the four immediately preceding fiscal quarters ended June 30, 2014 due to increased debt balances at a higher average interest rate than during previous periods combined with lower revenues mainly due to decreased oil production and lower oil prices. This covenant breach is an event of default under the credit facility.

As a result of this covenant breach, on July 31, 2014 the Company entered into a forbearance agreement with its senior secured lenders under the Amended Revolving Credit Facility. Pursuant to the Forbearance Agreement, the lenders, as well as the counterparties to certain outstanding hedging agreements with the Company, have agreed to forbear from exercising any rights or remedies that any of them may have, or from initiating or instituting legal proceedings, against the Company or any of the subsidiary guarantors under the Amended Revolving Credit Facility, or from realizing on their security granted in connection with the Credit Agreement, until the earlier of September 30, 2014 or the occurrence of an event of default within the meaning of the Forbearance Agreement. Pursuant to the terms of the Forbearance Agreement, among other provisions, the borrowing base was permanently reduced to zero, thereby preventing additional borrowings under the Amended Revolving Credit Facility. The Company also agreed to maintain $4.0 million in deposit accounts with the administrative agent in connection with the settlement of the outstanding hedging agreements.

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, 2013.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, 2013.

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

Commodity Price Risk

Our primary market risk exposure is in the pricing applicable to our crude oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our United States natural gas production. Pricing for crude oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Hypothetical changes in commodity prices chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations. However, since it is not possible to accurately predict future changes in commodity prices, this hypothetical change may not necessarily be an indicator of probable future fluctuations. Based on our average daily production for the six months ended June 30, 2014, our annual oil sales would increase or decrease by approximately $7.7 million for each $10.00 per barrel change in crude oil prices and our annual gas sales would increase or decrease by approximately $13.2 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 contracts 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 Item 1, Note 3, “Fair Value Measurements” and Item 1, 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 ($1.0 million at June 30, 2014) and the sale of our crude oil and natural gas production, which we market to energy marketing companies, refineries and affiliates ($19.9 million in receivables at June 30, 2014). Joint interest receivables arise from billing entities who own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. In order to minimize our exposure to credit risk we request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. In this manner, we reduce credit risk. We also have the right to place a lien on our co-owners interest in the well to redirect production proceeds in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.

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

Interest Rate Risk

Our exposure to changes in interest rates relates primarily to long-term debt obligations. Historically, we were exposed to changes in interest rates as a result of our revolving credit facility, and this exposure will remain under our Amended Revolving Credit Facility. There were no amounts outstanding under the Amended Revolving Credit Facility at June 30, 2014. We do not believe our interest rate exposure warrants entry into interest rate hedges and have, therefore, not hedged our interest rate exposure.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. We have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this Quarterly Report on Form 10-Q. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2014 to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (1) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) is accumulated and communicated to management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting. There was no change in our internal control over financial reporting that occurred during the quarter ended June 30, 2014, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

As previously disclosed, on January 25, 2011, the Company filed suit against the United States Government in United States Court of Federal Claims in Washington D.C. claiming a breach of contract on the lease governing the EB 920 Project, an offshore lease located in the deep waters of the Gulf of Mexico. In March 2013, the United States Court of Federal Claims granted the U.S. Government’s motion for summary judgment on those claims. On March 29, 2013, the Company filed an appeal to the summary judgment in United States Federal Circuit Court of Appeal in Washington D.C., reasserting our claim of a breach of contract by the U.S. Government with respect to the EB 920 Project. There are a number of issues relative to the Government’s breach of the Company’s lease. A major claim of breach is that due to the post-lease change in the rules of calculation of the WCD under Notice to Lessees 2010-06 (“NTL06”), the Company can no longer receive a permit to drill EB 920. The Company cannot develop the lease or receive the benefit of the proved reserves which exist on the lease and for which the Company paid the Government $23.2 million. The new post-lease rules of calculation for WCD did not exist prior to the issuance of NTL06. The Company argues that the post-lease changes to the method of the calculation are substantive both in terms of volumes and financial responsibility. The Government argues they are not substantive. A panel of judges heard the appeal in early January 2014. In March 2014, our appeal was denied. On April 24, 2014, the Company filed a Combined Petition for Panel Rehearing and for Rehearing En Banc. In July 2014, our Combined Petition for Panel Rehearing and for Rehearing En Banc was denied.

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

Item 1A. Risk Factors

As a result of being in default under our Credit Agreement, we recently entered into a Forbearance Agreement with certain of our secured lenders, pursuant to which the borrowing base under the Amended Revolving Credit Facility was permanently reduced to zero, thereby preventing additional borrowings, and we must maintain $4.0 million in deposit accounts with the lenders. The failure to obtain new sources financing on acceptable terms could adversely affect our business, financial condition and results of operations.

The Credit Agreement governing the Amended Revolving Credit Facility includes covenants restricting certain of our financial ratios, including an interest coverage ratio covenant, which specifies that we must maintain at least a 2.5 to 1.0 interest coverage ratio for the four immediately preceding consecutive fiscal quarters. For the four immediately preceding fiscal quarters ended June 30, 2014, our interest coverage ratio was 2.3 to 1.0. We did not meet this covenant for the four immediately preceding fiscal quarters ended June 30, 2014 due to increased debt balances at a higher average interest rate than during previous periods combined with lower revenues mainly due to decreased oil production and lower oil prices. This covenant breach is an event of default under the Credit Agreement.

As a result of this covenant breach, on July 31, 2014 we entered into a Forbearance Agreement with the senior secured lenders under the Amended Revolving Credit Facility. Pursuant to the Forbearance Agreement, the lenders, as well as the counterparties to certain of our outstanding hedging agreements, have agreed to forbear from exercising any rights or remedies that any of them may have, or from initiating or instituting legal proceedings, against us or any of the subsidiary guarantors under the Amended Revolving Credit Facility, or from realizing on their security granted in connection with the Credit Agreement, until the earlier of September 30, 2014 or the occurrence of an event of default within the meaning of the Forbearance Agreement. Pursuant to the terms of the Forbearance Agreement, the borrowing base was permanently reduced to zero, thereby preventing additional borrowings under the Amended Revolving Credit Facility. We also agreed to maintain $4.0 million in deposit accounts with the administrative agent in connection with the settlement of the outstanding hedging agreements.

We are currently working to secure new financing; however, there can be no assurance of additional financing being available or on acceptable terms to us. The failure to obtain additional financing could adversely affect our business, financial condition and results of operations.

Our exploration, development, production and exploitation projects require substantial capital expenditures. We may be unable to obtain necessary capital or financing on satisfactory terms, which could lead to a decline in our crude oil and natural gas reserves.

The crude oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, production, exploitation and acquisition of crude oil and natural gas reserves. Improvement in commodity prices may result in an increase in our actual capital expenditures. Conversely, a significant decline in product prices could result in a decrease in our capital expenditures.

Our financing needs may require us to alter or increase our capitalization substantially. The issuance of additional debt may require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our cash flows from operations and access to capital are subject to a number of variables, including:

•

our proved reserves;

•

the level of crude oil and natural gas we are able to produce from existing wells;

•

the prices at which our crude oil and natural gas are sold; and

•

our ability to acquire, locate and produce new reserves.

If our revenues decrease as a result of lower crude oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. In addition, pursuant to the terms of the Forbearance Agreement, the borrowing base under the Amended Revolving Credit Facility was permanently reduced to zero, thereby preventing additional borrowings thereunder. Because we intend to finance our future capital expenditures primarily through cash flows from operations and through borrowings, we are currently working to secure new financing; however, there can be no assurance of additional financing being available or on acceptable terms to us. If cash generated by operations is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our crude oil and natural gas reserves, and could adversely affect our business, financial condition and results of operations.

In addition to the information set forth in this Form 10-Q, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013 that was filed with the SEC on March 31, 2014, which could materially affect our business, financial condition or future results. You should also consider the matters addressed under “Cautionary Note Regarding Forward-Looking Statements.” Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially adversely affect our business, financial condition or results of operations.

Item 6. Exhibits

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

SIGNATURES

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


RAAM Global Energy Company

	By: RAAM Global Energy Company

August 13, 2014		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)).

10.1		Forbearance Agreement, dated as of July 31, 2014, by and among Century Exploration New Orleans, LLC, Century Exploration Houston, LLC, Century Exploration Resources, LLC, RAAM Global Energy Company, Union Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.1 to the Form 8-K filed on August 5, 2014 (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 June 30, 2014 and December 31, 2013; (ii) our Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013; (iii) our Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013; and (iv) the notes to our unaudited Condensed Consolidated Financial Statements.

*	Filed herewith.

**	Furnished herewith.

RAAM Global Energy Co - FORM 10-Q - August 13, 2014

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