UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended September 30, 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 November 10, 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		41
Item 4. Controls and Procedures		42

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

SIGNATURES		44

Exhibit Index		45

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)


	September 30, 2014			December 31, 2013
Assets
Current assets:
Cash and cash equivalents	$	152,471		$	90,858
Accounts receivable, net of $210 and $656 provision for bad debts in 2014 and 2013, respectively		1,410			5,472
Revenues receivable		15,829			19,517
Income taxes receivable		1,109			507
Deferred tax asset – current portion		3,487			3,938
Prepaid expenses		3,309			3,863
Other current assets		6,583			4,596

Total current assets		184,198			128,751

Oil and gas properties (full-cost method):
Properties being amortized		1,483,249			1,432,310
Properties not subject to amortization		47,903			45,752
Less accumulated depreciation, depletion, and amortization		(1,247,799	)		(1,190,944	)

Net oil and gas properties		283,353			287,118

Other assets:
Other capitalized assets, net		6,516			7,252
Commodity derivatives		244			1,541
Other		143			1,950

Total other assets		6,903			10,743

Total assets	$	474,454		$	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)


	September 30, 2014			December 31, 2013
Liabilities and equity
Current liabilities:
Accounts payable and accrued liabilities	$	20,044		$	28,066
Revenues payable		14,726			17,699
Interest payable—senior secured notes		15,625			7,813
Current taxes payable		—			25
Advances from joint interest partners		436			4,852
Commodity derivatives—current portion		234			4,467
Asset retirement obligations—current portion		13,563			14,089
Debt—current portion		86,798			2,626

Total current liabilities		151,426			79,637

Other liabilities:
Commodity derivatives		—			10
Asset retirement obligations		30,529			29,138
Debt		2,331			2,448
Senior secured notes		250,593			251,037
Deferred income taxes		7,145			14,178
Other long-term liabilities		221			149

Total other liabilities		290,819			296,960

Total liabilities		442,245			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		(22,110	)		(7,441	)

Total equity attributable to RAAM Global shareholders		32,872			47,528
Noncontrolling interest		(663	)		2,487

Total equity		32,209			50,015

Total liabilities and equity	$	474,454		$	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 September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Revenues:
Gas sales	$	14,035		$	15,268		$	48,469		$	47,760
Oil sales		16,565			24,797			55,335			74,588
Gains (losses) on derivatives, net		4,631			(1,729	)		(4,009	)		(2,204	)

Total revenues		35,231			38,336			99,795			120,144

Costs and expenses:
Production and delivery costs		6,574			7,253			20,240			23,192
Production taxes		1,827			1,992			5,991			5,902
Workover costs		16			1,151			2,131			2,609
Depreciation, depletion and amortization		17,036			310,090			58,941			346,271
General and administrative expenses		2,752			4,594			9,188			14,223

Total operating expense		28,205			325,080			96,491			392,197


Income (loss) from operations		7,026			(286,744	)		3,304			(272,053	)

Other income (expenses):
Interest expense, net		(8,578	)		(7,813	)		(24,567	)		(22,362	)
Other, net		(335	)		(5	)		387			(152	)

Total other income (expenses)		(8,913	)		(7,818	)		(24,180	)		(22,514	)

Loss before taxes		(1,887	)		(294,562	)		(20,876	)		(294,567	)

Income tax benefit		(3,077	)		(109,241	)		(6,953	)		(109,267	)

Net income (loss) including noncontrolling interest	$	1,190		$	(185,321	)	$	(13,923	)	$	(185,300	)


Net income attributable to noncontrolling interest (net of tax)		—			224			746			1,174

Net income (loss) attributable to RAAM Global	$	1,190		$	(185,545	)	$	(14,669	)	$	(186,474	)

See accompanying notes to the unaudited condensed consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2014			2013
Operating activities
Net loss including noncontrolling interest	$	(13,923	)	$	(185,300	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		60,596			347,653
Deferred income taxes		(6,582	)		(103,636	)
Stock-based compensation expense		12			—
Lower of cost or market inventory adjustment		343			—
Changes in assets and liabilities:
Accounts and revenues receivable		7,245			5,729
Income tax receivables		(602	)		1,438
Prepaids and other current assets		645			(2,327	)
Change in derivatives, net		(2,946	)		1,748
Accounts payable and accrued liabilities		(917	)		1,714
Revenues payable		(2,973	)		(6,033	)
Interest payable on Senior Secured Notes		7,812			9,375
Current taxes payable		(25	)		471
Settlements of asset retirement obligations		(7,284	)		(3,479	)
Other long-term liabilities		73			(207	)

Net cash provided by operating activities		41,474			67,146

Investing activities
Change in advances from joint interest partners		(4,417	)		6,676
Additions to oil and gas properties and equipment		(49,099	)		(98,035	)
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		(57,931	)		(74,039	)

Financing activities
Proceeds from borrowings		88,678			6,757
Payments on borrowings		(4,622	)		(54,987	)
Issuance of Senior Secured Notes		—			51,500
Purchase of noncontrolling interest		(3,272	)		—
Deferred loan costs		(2,721	)		—
Payments of deferred bond costs		—			(1,540	)
Payment of dividends		—			(1,563	)
Other		7			—

Net cash provided by financing activities		78,070			167


Increase (decrease) in cash and cash equivalents		61,613			(6,726	)
Cash and cash equivalents, beginning of period		90,858			68,671

Cash and cash equivalents, end of period	$	152,471		$	61,945

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 $1.9 million and $1.5 million for the three months ended September 30, 2014 and 2013, respectively, and $5.4 million and $4.6 million for the nine months ended September 30, 2014 and 2013, respectively. The Company capitalized interest of $0.4 million and $0.5 million during the three months ended September 30, 2014 and 2013, respectively, related to properties not subject to amortization where significant activity occurred during the period. The Company capitalized interest of $1.0 million and $1.3 million during the nine months ended September 30, 2014 and 2013, respectively, related to properties not subject to amortization where significant activity occurred during the period.

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 $47.9 million and $45.8 million at September 30, 2014 and December 31, 2013, respectively. The Company believes that the unevaluated properties at September 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, commodity prices are calculated using the average of the first-day-of-the-month price for the trailing 12-month period.

At September 30, 2014, the Company’s ceiling test computation resulted in a $0.4 million write-down and was based on the trailing 12-month average prices of $95.56 per barrel of oil plus adjustments by lease for quality, transportation fees, and regional price differentials and $4.24 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 the trailing 12-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 during that period and was based on the trailing 12-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 for a net purchase price of $4.9 million. The Company obtained a reserve report from independent reserve engineers, which was used to help determine the purchase price. 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 from independent reserve engineers. The purchase was approved by the Company’s Board of Directors. 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. Prior to the transaction, Charter V was a consolidated variable interest entity (“VIE”) of the Company. The Company completed the purchase on July 2, 2014.

There are certain related parties 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, 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 recognizes necessary increases or decreases as changes in estimates in the respective quarter. The Company evaluates on a quarterly basis 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 ARO 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		1,044
Additions		401
Settlement of ARO		(7,284	)
Change in ARO estimates		6,704

Balance of ARO as of September 30, 2014	$	44,092

The change in ARO estimates during the nine months ended September 30, 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. ARO estimates also increased on certain previously existing platforms and facilities in state waters as a result of additional development.

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


	Fair Value Measurements Using⁽¹⁾
*In Thousands*	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Fair Value			Netting			Carrying Amount
September 30, 2014
Assets:
Commodity derivatives	$	—	$	2,389		$	—	$	2,389		$	(2,145	)	$	244
Liabilities:
Commodity derivatives		—		(2,379	)		—		(2,379	)		2,145			(234	)
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 when the legal right of offset exists.

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	September 30, 2014			December 31, 2013
*In thousands*
Assets:
Fair value of commodity derivatives—current assets	$	—		$	—
Fair value of commodity derivatives—long-term assets		244			1,541

Total Assets	$	244		$	1,541


Liabilities:
Fair value of commodity derivatives—current liabilities	$	(234	)	$	(4,467	)
Fair value of commodity derivatives—long-term liabilities		—			(10	)

Total Liabilities	$	(234	)	$	(4,477	)

At September 30, 2014, the fair value of the Company’s senior secured notes (the “Notes”) was estimated to be approximately $191.3 million, based on the prices the bonds have recently been quoted at in the market. This represents a Level 2 valuation as the market for the bonds is not considered to be active. As of September 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 $250.6 million as of September 30, 2014.

At December 31, 2013, the fair value of the Notes was estimated to be approximately $259.1 million, based on a Level 2 valuation. 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 Term Loan Facility (as defined in Note 6) are at variable interest rates and accordingly their carrying amounts approximate fair value.

4. Accounts and Revenues Receivable

Accounts and revenues receivable at September 30, 2014 and December 31, 2013 were $17.2 million and $25.0 million, respectively, all of which were due from companies in the oil and gas industry. Since all of the Company’s accounts receivable from purchasers and joint interest owners at September 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 September 30, 2014 and December 31, 2013. Management obtains letters of credit from 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, 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. As required by the Fifth Amended and Restated Credit Agreement (as defined in Note 6), the Company’s derivative counterparties are limited to our secured lenders, which helps to minimize any potential non-performance risk.

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 September 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, 2015 and 2016:


Remaining Contract Term	Contract Type	Volume in MMBtus/ Month		NYMEX Strike Price
October 2014—December 2014	Swap		61,333	$	4.15
October 2014—December 2014	Swap		143,000	$	3.91
October 2014—December 2014	Swap		297,329	$	4.09
January 2015—December 2015	Swap		375,806	$	4.01
October 2014—December 2014	Call—Sell		312,800	$	5.00
October 2014—December 2014	Call—Buy		312,800	$	4.50
January 2015—December 2015	Put—Sell		316,430	$	3.50
January 2016—December 2016	Put—Buy		240,397	$	4.00
January 2016—December 2016	Put—Sell		240,397	$	3.50
January 2016—December 2016	Call—Sell		240,397	$	4.73

As of September 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, 2015 and 2016:


Remaining Contract Term	Contract Type	Volume in BBls/ Month		NYMEX Strike Price
October 2014—December 2014	Swap		3,261	$	92.90
October 2014—December 2014	Swap		27,077	$	90.62
January 2015—December 2015	Swap		22,338	$	89.44
January 2016—December 2016	Swap		15,335	$	88.12

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

Subsequent to September 30, 2014, the Company entered into the following commodity derivative instruments shown below related to the forecasted sale of its U.S. Gulf Coast natural gas production for 2015 and 2016:


Contract Term	Contract Type	Volume in MMBtus/ Month		NYMEX Strike Price
January 2015—March 2015	Swap		212,973	$	4.09
January 2016	Swap		81,354	$	4.02
January 2016—March 2016	Swap		120,675	$	4.10

6. Debt

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 its previous credit facility 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 previous 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 Term Loan 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 Term Loan Facility, subject to certain exceptions. Pursuant to an Intercreditor Agreement, the lien securing the Notes is subordinated and junior to liens securing our Term Loan Facility.

The Company is actively working with investment banking advisors to prepare for refinancing the Notes in 2015. In conjunction with these advisors, the Company has developed and is executing a robust drilling program. The Company has established a timetable in which a significant number of wells will be drilled and completed prior to the refinancing. The Company believes that the addition of these wells will increase production and reserves and will lead to future drilling opportunities in our core project areas.

Term Loan Facility

On September 12, 2014, the Company entered into a Fifth Amended and Restated Credit Agreement with Wilmington Trust, National Association, as administrative agent and the lenders party thereto (the “Fifth Amended and Restated Credit Agreement”). The Fifth Amended and Restated Credit Agreement provides the Company with an $85.0 million term loan facility (the “Term Loan Facility”) which is secured by a first lien on substantially all of the Company’s real and personal property. As of September 30, 2014, $85.0 million was outstanding under the Term Loan Facility. The maturity date for the Term Loan Facility is the earlier of September 12, 2016 or 91 days prior to the maturity date of the Senior Secured Notes. The annual interest rate on the Term Loan Facility is 6.5%, plus the greater of the LIBOR rate for the interest period or 1%. At September 30, 2014, the interest rate was 7.5%. Interest is payable quarterly on September 30, December 31, March 31, and June 30 of each year, which commenced on September 30, 2014.

The proceeds of the term loan incurred under the Fifth Amended and Restated Credit Agreement were or will be used to (a) repay all expenses, fees or indemnitees outstanding under the Fourth Amended and Restated Credit Agreement dated as of November 29, 2011, (b) finance capital expenditures associated with the Company’s oil and gas properties, (c) provide working capital for the Company’s operations and (d) pay transaction fees and expenses incurred in connection with the transactions contemplated by the Fifth Amended and Restated Credit Agreement. The Fifth Amended and Restated Credit Agreement contains customary restrictions on, among other things the Company’s ability to incur debt, grant liens on their property, make dispositions or investments, enter into mergers or issue new securities, make distributions, enter into affiliate transactions, enter into hedging contracts, amend their organizational documents and create new subsidiaries. In addition, the Fifth Amended and Restated Credit Agreement requires the Company to maintain the following financial covenants as defined in the agreement: (i) a minimum Current Ratio of 1.0:1.0 as of the end of each fiscal quarter, (ii) a maximum First Lien Leverage Ratio of 2.0:1.0 as of the end of each fiscal quarter for the four immediately preceding fiscal quarters and (iii) a minimum PDP Asset Coverage Ratio of 1.0:1.0 as of January 1, 2015 and 1.1:1.0 as of April 1, 2015, July 1, 2015, January 1, 2016 and July 1, 2016. As of September 30, 2014, the Company was in compliance with all of these debt covenants.

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 September 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 September 30, 2014, $2.5 million was outstanding under this agreement. The finance agreement requires 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 September 30, 2014 was $3.1 million or an effective tax rate of 163.0% compared to an income tax benefit of $109.2 million or an effective tax rate of 37.1% for the three months ended September 30, 2013. Income tax benefit for the nine months ended September 30, 2014 was $7.0 million or an effective tax rate of 33.3% compared to an income tax benefit of $109.3 million or an effective tax rate of 37.1% for the nine months ended September 30, 2013. The Company’s effective income tax rates for the three and nine months ended September 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 rates for the three and nine months ended September 30, 2013 differed from the federal statutory rate of 35.0% primarily because of state and local income taxes and percentage depletion in excess of cost basis.

8. Shareholders’ Equity

During the nine months ended September 30, 2014, no dividends were paid. During the nine months ended September 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 parties that are joint interest and revenue partners in certain of the Company’s properties. Amounts due from such related parties of $10,000 and $1.1 million at September 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 $95,000 and $2.0 million at September 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, which was used to help determine the purchase price. 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 September 30, 2014 and December 31, 2013, condensed consolidating statements of operations for the three and nine months ended September 30, 2014 and 2013, and condensed consolidating statements of cash flows for the nine months ended September 30, 2014 and 2013, and should be read in conjunction with the condensed consolidated financial statements herein.

Condensed Consolidating Balance Sheets

At September 30, 2014 (in thousands)


	RAAM Global Energy Company		Subsidiary Guarantors		Non-guarantor VIE			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	751	$	151,720	$	—		$	—		$	152,471
Receivables, net		1,109		20,367		—			(3,128	)		18,348
Deferred tax asset—current		—		3,487		—			—			3,487
Commodity derivatives—current portion		—		—		—			—			—
Prepaids and other current assets		4,316		5,576		—			—			9,892

Total current assets		6,176		181,150		—			(3,128	)		184,198

Net oil and gas properties		—		280,355		2,998			—			283,353

Total other assets		302,241		807		—			(296,145	)		6,903

Total assets	$	308,417	$	462,312	$	2,998		$	(299,273	)	$	474,454

Liabilities and equity
Current liabilities:
Payables and accrued liabilities	$	17,060	$	33,335	$	3,128		$	(3,128	)	$	50,395
Advances from joint interest partners		—		436		—			—			436
Commodity derivatives—current portion		—		234		—			—			234
Asset retirement obligations—current portion		—		13,563		—			—			13,563
Debt—current portion		142		86,656		—			—			86,798

Total current liabilities		17,202		134,224		3,128			(3,128	)		151,426

Other liabilities:
Commodity derivatives		—		—		—			—			—
Asset retirement obligations		—		30,529		—			—			30,529
Long-term debt		2,331		—		—			—			2,331
Senior secured notes		250,593		—		—			—			250,593
Deferred income taxes		5,198		1,414		533			—			7,145
Other long-term liabilities		221		—		—			—			221

Total other liabilities		258,343		31,943		533			—			290,819
Total liabilities		275,545		166,167		3,661			(3,128	)		442,245

Equity attributable to RAAM Global shareholders		32,872		296,145		—			(296,145	)		32,872
Noncontrolling interest		—		—		(663	)		—			(663	)

Total equity		32,872		296,145		(663	)		(296,145	)		32,209

Total liabilities and equity	$	308,417	$	462,312	$	2,998		$	(299,273	)	$	474,454

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
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 September 30, 2014 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Eliminations			Consolidated
Revenues:
Gas sales	$	—		$	14,035		$	—		$	14,035
Oil sales		—			16,565			—			16,565
Gains on derivatives, net		—			4,631			—			4,631

Total revenues		—			35,231			—			35,231
Costs and expenses:
Production and delivery costs		—			6,574			—			6,574
Production taxes		—			1,827			—			1,827
Workover costs		—			16			—			16
Depreciation, depletion and amortization		77			16,959			—			17,036
General and administrative expenses		1,475			1,277			—			2,752

Total operating expense		1,552			26,653			—			28,205

Income (loss) from operations		(1,552	)		8,578			—			7,026
Other income (expenses):
Interest expense, net		(8,015	)		(563	)		—			(8,578	)
Income from equity investment in subsidiaries		10,371			—			(10,371	)		—
Other, net		—			(335	)		—			(335	)

Total other income (expenses)		2,356			(898	)		(10,371	)		(8,913	)

Income (loss) before taxes		804			7,680			(10,371	)		(1,887	)
Income tax benefit		(386	)		(2,691	)		—			(3,077	)

Net income (loss) including noncontrolling interest	$	1,190		$	10,371		$	(10,371	)		1,190

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

Net income (loss) attributable to RAAM Global	$	1,190		$	10,371		$	(10,371	)	$	1,190

The non-guarantor VIE had no activity for the three months ended September 30, 2014.

Condensed Consolidating Statements of Operations

Three Months Ended September 30, 2013 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs		Eliminations		Consolidated
Revenues:
Gas sales	$	—		$	14,435		$	833	$	—	$	15,268
Oil sales		—			23,883			914		—		24,797
Losses on derivatives, net		—			(1,729	)		—		—		(1,729	)

Total revenues		—			36,589			1,747		—		38,336
Costs and expenses:
Production and delivery costs		—			7,143			110		—		7,253
Production taxes		—			1,912			80		—		1,992
Workover costs		—			1,128			23		—		1,151
Depreciation, depletion and amortization		197			308,722			1,171		—		310,090
General and administrative expenses		2,550			2,044			—		—		4,594

Total operating expense		2,747			320,949			1,384		—		325,080

Income (loss) from operations		(2,747	)		(284,360	)		363		—		(286,744	)
Other income (expenses):
Interest expense, net		(7,779	)		(34	)		—		—		(7,813	)
Income from equity investment in subsidiaries		(180,487	)		—			—		180,487		—
Other, net		—			(5	)		—		—		(5	)

Total other income (expenses)		(188,266	)		(39	)		—		180,487		(7,818	)

Income (loss) before taxes		(191,013	)		(284,399	)		363		180,487		(294,562	)
Income tax (benefit) provision		(5,692	)		(103,688	)		139		—		(109,241	)

Net income (loss) including noncontrolling interest	$	(185,321	)	$	(180,711	)	$	224	$	180,487	$	(185,321	)

Net income attributable to noncontrolling interest (net of tax)		224			—			—		—		224

Net income (loss) attributable to RAAM Global	$	(185,545	)	$	(180,711	)	$	224	$	180,487	$	(185,545	)

Condensed Consolidating Statements of Operations

Nine Months Ended September 30, 2014 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs		Eliminations			Consolidated
Revenues:
Gas sales	$	—		$	46,822		$	1,647	$	—		$	48,469
Oil sales		—			54,202			1,133		—			55,335
Losses on derivatives, net		—			(4,009	)		—		—			(4,009	)

Total revenues		—			97,015			2,780		—			99,795
Costs and expenses:
Production and delivery costs		—			20,066			174		—			20,240
Production taxes		—			5,819			172		—			5,991
Workover costs		—			2,131			—		—			2,131
Depreciation, depletion and amortization		257			57,264			1,420		—			58,941
General and administrative expenses		5,877			3,303			8		—			9,188

Total operating expense		6,134			88,583			1,774		—			96,491

Income (loss) from operations		(6,134	)		8,432			1,006		—			3,304
Other income (expenses):
Interest expense, net		(23,954	)		(613	)		—		—			(24,567	)
Loss from equity investment		—			—			—		—			—
Loss on disposals of inventory		—			—			—		—			—
Income from equity investment in subsidiaries		14,730			—			—		(14,730	)		—
Other, net		308			79			—		—			387

Total other income (expenses)		(8,916	)		(534	)		—		(14,730	)		(24,180	)

Income (loss) before taxes		(15,050	)		7,898			1,006		(14,730	)		(20,876	)
Income tax (benefit) provision		(381	)		(6,832	)		260		—			(6,953	)

Net income (loss) including noncontrolling interest	$	(14,669	)	$	14,730		$	746	$	(14,730	)		(13,923	)

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

Net income (loss) attributable to RAAM Global	$	(14,669	)	$	14,730		$	—	$	(14,730	)	$	(14,669	)

Condensed Consolidating Statements of Operations

Nine Months Ended September 30, 2013 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs		Eliminations		Consolidated
Revenues:
Gas sales	$	—		$	45,383		$	2,377	$	—	$	47,760
Oil sales		—			71,832			2,756		—		74,588
Losses on derivatives, net		—			(2,204	)		—		—		(2,204	)

Total revenues		—			115,011			5,133		—		120,144
Costs and expenses:
Production and delivery costs		—			22,853			339		—		23,192
Production taxes		—			5,688			214		—		5,902
Workover costs		—			2,579			30		—		2,609
Depreciation, depletion and amortization		558			343,052			2,661		—		346,271
General and administrative expenses		6,482			7,737			4		—		14,223

Total operating expense		7,040			381,909			3,248		—		392,197

Income (loss) from operations		(7,040	)		(266,898	)		1,885		—		(272,053	)
Other income (expenses):
Interest expense, net		(21,819	)		(543	)		—		—		(22,362	)
Income from equity investment in subsidiaries		(161,944	)		—			—		161,944		—
Other, net		(150	)		(2	)		—		—		(152	)

Total other income (expenses)		(183,913	)		(545	)		—		161,944		(22,514	)

Income (loss) before taxes		(190,953	)		(267,443	)		1,885		161,944		(294,567	)
Income tax (benefit) provision		(5,653	)		(104,325	)		711		—		(109,267	)

Net income (loss) including noncontrolling interest	$	(185,300	)	$	(163,118	)	$	1,174	$	161,944	$	(185,300	)

Net income attributable to noncontrolling interest (net of tax)		1,174			—			—		—		1,174

Net income (loss) attributable to RAAM Global	$	(186,474	)	$	(163,118	)	$	1,174	$	161,944	$	(186,474	)

Condensed Consolidating Statements of Cash Flows

Nine Months Ended September 30, 2014 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(15,301	)	$	69,096		$	2,409		$	(14,730	)	$	41,474
Investing activities
Change in investments between affiliates		20,893			(33,880	)		(1,743	)		14,730			—
Change in advances from joint interest partners		—			(4,417	)		—			—			(4,417	)
Additions to oil and gas properties and equipment		(5	)		(48,423	)		(671	)		—			(49,099	)
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		20,888			(91,135	)		(2,414	)		14,730			(57,931	)
Financing activities
Proceeds from borrowings		—			88,678			—			—			88,678
Payments on borrowings		(122	)		(4,500	)		—			—			(4,622	)
Deferred loan costs		(2,070	)		(651	)		—			—			(2,721	)
Purchase of noncontrolling interest		(3,272	)		—			—			—			(3,272	)
Other		—			7			—			—			7

Net cash provided by (used in) financing activities		(5,464	)		83,534			—			—			78,070

Increase (decrease) in cash and cash equivalents		123			61,495			(5	)		—			61,613
Cash and cash equivalents, beginning of period		628			90,225			5			—			90,858

Cash and cash equivalents, end of period	$	751		$	151,720		$	—		$	—		$	152,471

Condensed Consolidating Statements of Cash Flows

Nine Months Ended September 30, 2013 (in thousands)


	RAAM Global Energy Company			Subsidiary Guarantors			Non-guarantor VIEs			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(172,141	)	$	72,777		$	4,566		$	161,944		$	67,146
Investing activities
Change in investments between affiliates		133,583			31,495			(3,134	)		(161,944	)		—
Change in advances from joint interest partners		—			6,676			—			—			6,676
Additions to oil and gas properties and equipment		(2,362	)		(94,237	)		(1,436	)		—			(98,035	)
Proceeds from net sales of oil and gas properties		—			17,320			—			—			17,320

Net cash provided by (used in) investing activities		131,221			(38,746	)		(4,570	)		(161,944	)		(74,039	)
Financing activities
Proceeds from borrowings		—			6,757			—			—			6,757
Payments on borrowings		(102	)		(54,885	)		—			—			(54,987	)
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		48,295			(48,128	)		—			—			167

Increase (decrease) in cash and cash equivalents		7,375			(14,097	)		(4	)		—			(6,726	)
Cash and cash equivalents, beginning of period		514			68,148			9			—			68,671

Cash and cash equivalents, end of period	$	7,889		$	54,051		$	5		$	—		$	61,945

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 of our conventional plays and also 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 Yegua and Cook Mountain region and the Mid-Continent region. We were successful in obtaining a farm-out partner in our Breton Sound area. We are currently developing and executing an active drilling program in our four core areas: Shallow Waters (Breton Sound and Palmetto), Federal Waters of the Gulf of Mexico, Texas Yegua Trend and the California Stevens play.

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.

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

During the third quarter of 2014, the Company successfully entered into the Fifth Amended and Restated Credit Agreement, which provides the Company with an $85.0 million term loan facility. After completing this new financing arrangement, the Company launched an active drilling program. The Company believes the wells selected for this program have the best chance of proving up new reserves, increasing cash flow, and establishing future drilling opportunities.

Shallow Waters—Breton Sound. During September 2014, the first successful farm-out well was brought online. As of November 10, 2014, this well was producing at a rate of 10.5 million cubic feet per day and 621 barrels of condensate per day. The Company has a 22.4% Net Revenue Interest in this well. Another farm-out well is scheduled to be spud in late November 2014. The Company has completed its proprietary 3-D survey over another prospect area in this field. The Company maintains a 100% working interest in this area and expects to spud the prospect in December 2014. The Breton Sound field has several additional locations to be drilled.

Shallow Waters—Palmetto. The Company has opened a new area of exploration in the State Waters of Louisiana. The Company has 3,173 acres under lease. The first Palmetto well was spud on October 25, 2014, and is currently drilling. There could be as many as four additional locations to be drilled in the Palmetto lease based on the success of the initial well.

Offshore Federal Waters of the Gulf of Mexico. The Company is in the process of permitting a well to be drilled off its currently producing platform in Ship Shoal Block 150 in the Gulf of Mexico. The well is scheduled to be spud in November and estimated to reach total depth in January 2015.

Texas Yegua Trend. On November 3, 2014, the Company brought a new well online in the Texas Yegua Trend. As of November 10, 2014, the well was producing 2.3 million cubic feet per day and 87 barrels of condensate. The Company has a 48.1% Net Revenue Interest in this well. On November 5, 2014, the Company mobilized a rig to drill another prospect in the Texas Yegua Trend. It is estimated that the well will be drilled and logged prior to December 31, 2014.

California Stevens Play. In October 2014, the first California Stevens well was drilled and successfully completed and placed into production. As of November 10, 2014, the well was producing 280 barrels of oil per day. The Company has a 79.7% Net Revenue Interest in this well. On September 22, 2014, the Company spud the second California Stevens well and is currently drilling this well. The well is expected to reach total depth and be logged prior to December 31, 2014. The Company believes the California Stevens play has as many as ten to fifteen additional locations to be drilled based on the success of the second well which is currently being drilled.

In summary, the Company has drilled or participated in three successful wells which are currently online and producing: a Breton Sound farm-out well, a Texas Yegua Trend well, and a California Stevens well. The Company currently has two wells drilling: a Palmetto well in the State waters of Louisiana and a California Stevens well. The Company expects to have three additional wells spud in November 2014: a Breton Sound farm-out well, a Texas Yegua Trend well, and a Ship Shoal 150 well in the Federal Waters of the Gulf of Mexico. In addition, the Company expects to spud a 100% Company-owned prospect in the Breton Sound field in December 2014.

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 nine month periods ended September 30, 2014 and 2013.


	Three Months Ended September 30,					Nine Months Ended September 30,
	2014		2013			2014			2013
Average daily production:
Oil (Bbl per day)		1,827		2,349			2,006			2,489
Natural gas (Mcf per day)		32,942		41,033			35,071			41,717
Oil equivalents (Boe per day)		7,318		9,188			7,851			9,442

Average prices:⁽¹⁾
Oil ($/Bbl)	$	98.53	$	114.73		$	101.05		$	109.77
Natural gas ($/Mcf)	$	4.63	$	4.04		$	5.06		$	4.19
Oil equivalents ($/Boe)	$	45.45	$	47.40		$	48.43		$	47.47

Production and delivery costs ($/Boe)	$	9.76	$	8.58		$	9.44		$	9.00
General and administrative expenses ($/Boe)	$	4.09	$	5.43		$	4.29		$	5.52
Net income (loss) attributable to RAAM Global (in thousands)	$	1,190	$	(185,545	)	$	(14,669	)	$	(186,474	)
Adjusted EBITDA ⁽²⁾ (in thousands)	$	17,558	$	23,876		$	59,018		$	74,652

⁽¹⁾

Average prices presented do not give effect to our derivative activities or the monetization of oil derivatives during February 2013 or the monetization of oil and gas derivatives during June, July and September 2014. 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 nine month periods ended September 30, 2014 and 2013.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
*In thousands*
Net income (loss) attributable to RAAM Global	$	1,190		$	(185,545	)	$	(14,669	)	$	(186,474	)
Net (gains) losses on derivatives, net of cash settlements received or paid		(6,197	)		721			(2,946	)		1,684
Interest expense		8,606			7,851			24,645			22,438
Depreciation, depletion and amortization		17,036			310,090			58,941			346,271
Income taxes		(3,077	)		(109,241	)		(6,953	)		(109,267	)

Adjusted EBITDA	$	17,558		$	23,876		$	59,018		$	74,652

Results of Operations

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Revenues:
Gas sales	$	14,035		$	15,268		$	48,469		$	47,760
Oil sales		16,565			24,797			55,335			74,588
Gains (losses) on derivatives, net		4,631			(1,729	)		(4,009	)		(2,204	)

Total revenues		35,231			38,336			99,795			120,144
Costs and expenses:
Production and delivery costs		6,574			7,253			20,240			23,192
Production taxes		1,827			1,992			5,991			5,902
Workover costs		16			1,151			2,131			2,609
Depreciation, depletion and amortization		17,036			310,090			58,941			346,271
General and administrative expenses		2,752			4,594			9,188			14,223

Total operating expense		28,205			325,080			96,491			392,197

Income (loss) from operations		7,026			(286,744	)		3,304			(272,053	)
Other income (expenses):
Interest expense, net		(8,578	)		(7,813	)		(24,567	)		(22,362	)
Other, net		(335	)		(5	)		387			(152	)

Total other income (expenses)		(8,913	)		(7,818	)		(24,180	)		(22,514	)

Loss before taxes		(1,887	)		(294,562	)		(20,876	)		(294,567	)
Income tax benefit		(3,077	)		(109,241	)		(6,953	)		(109,267	)

Net income (loss) including noncontrolling interest	$	1,190		$	(185,321	)	$	(13,923	)	$	(185,300	)

Net income attributable to noncontrolling interest (net of tax)		—			224			746			1,174

Net income (loss) attributable to RAAM Global	$	1,190		$	(185,545	)	$	(14,669	)	$	(186,474	)

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

Revenues

Oil and natural gas production. Oil and natural gas production for the three months ended September 30, 2014 decreased to 0.7 MMBoe from 0.8 MMBoe for the three months ended September 30, 2013. During the three months ended September 30, 2014, natural gas production decreased 20% and oil production decreased 22%, resulting in a 20% decrease in Boe production as compared to the three months ended September 30, 2013. Oil and natural gas production decreased because the Company was engaged in limited drilling activity and production from new wells in both the shallow waters of Louisiana and onshore Texas did not offset normal production declines from our mature wells.

Total revenues. Total revenues for the three months ended September 30, 2014 decreased to $35.2 million from $38.3 million for the three months ended September 30, 2013. Natural gas revenues (exclusive of derivatives) decreased $1.2 million or 8% due to lower production even though natural gas prices were higher for the three months ended September 30, 2014 as compared to the three months ended September 30, 2013. Natural gas prices increased by 15% period over period, to an average price of $4.63 for the three months ended September 30, 2014 from an average natural gas price of $4.04 for the three months ended September 30, 2013.

Oil revenues (exclusive of derivatives) decreased $8.2 million or 33%, as compared to the prior year period due to lower oil volumes and lower oil prices. The average oil price of $98.53 for the three months ended September 30, 2014 represented a 14% decrease from the average oil price of $114.73 for the three months ended September 30, 2013.

Operating costs and expenses

Production and delivery costs. Production and delivery costs for the three months ended September 30, 2014 decreased to $6.6 million from $7.3 million for the same period in 2013. Production and delivery costs per Boe increased to $9.76 per Boe for the three months ended September 30, 2014 from $8.58 per Boe for the same period in 2013 primarily as a result of lower production volumes during the third quarter of 2014. In the third quarter of 2014 the Company experienced lower insurance, lift boat, and boat transportation costs than those during the same period in 2013.

Production taxes. Production taxes were $1.8 million for the three months ended September 30, 2014, and $2.0 million for the comparable period in 2013. The Company pays production taxes to state governments at rates specified by geographic location and commodity. Production taxes on natural gas increased by $0.1 million due to higher natural gas prices for the three months ended September 30, 2014 while production taxes on oil decreased by $0.3 million due to lower oil prices for the three months ended September 30, 2014.

Workover costs. Workover costs for the three months ended September 30, 2014 decreased to $16,000 from $1.2 million for the same period in 2013. Workovers are performed on wells that need certain mechanical changes or enhancements to maintain or increase production. Due to less mechanical needs during the third quarter of 2014, the Company performed less workovers in that period than were necessary during the same period in 2013.

Depreciation, depletion and amortization. Depreciation, depletion and amortization for the three months ended September 30, 2014 decreased to $17.0 million from $310.1 million for the three months ended September 30, 2013. Excluding the effects of the ceiling test write-down in each period depreciation, depletion and amortization for the three months ended September 30, 2014 decreased to $24.78 per Boe down from $39.25 per Boe for the three months ended September 30, 2013. The decrease in depreciation, depletion and amortization was primarily due to a $276.9 million ceiling test write-down to eliminate the proved reserves in the Ewing Bank 920 Project during the third quarter of 2013, as compared to a $0.4 million ceiling test write-down in the third quarter of 2014. At September 30, 2014, the Company also had a significantly lower cost basis to deplete than at September 30, 2013 resulting in less depletion in the third quarter of 2014.

General and administrative expenses. General and administrative expenses decreased to $2.8 million for the three months ended September 30, 2014 from $4.6 million for the three months ended September 30, 2013. The decrease in general and administrative expenses was mainly due to lower consultant compensation and data processing costs during the third quarter of 2014 as compared to the same period of 2013.

Interest expense, net. Net interest expense increased to $8.6 million for the three months ended September 30, 2014, from $7.8 million for the three months ended September 30, 2013 because of higher average debt balances. Debt balances averaged $266.6 million and $250.0 million during the three months ended September 30, 2014 and 2013, respectively. Effective annual interest rates averaged 12.2% and 12.5% during the three months ended September 30, 2014 and 2013, respectively. In both the third quarter of 2014 and 2013, the Company had $250.0 million of senior secured notes outstanding with a 12.5% interest rate. On September 12, 2014, the Company borrowed $85.0 million under its Term Loan Facility. At September 30, 2014 the effective interest rate was 7.5% on the Term Loan Facility. For additional information on the Term Loan Facility, see the “-Financing Facilities” below.

Income tax benefit. For the three months ended September 30, 2014, the Company recorded an income tax benefit of $3.1 million as compared to income tax benefit of $109.2 million for the three months ended September 30, 2013. Income tax benefits recognized were the result of effective tax rate calculations of approximately 163.0% at September 30, 2014 and approximately 37.1% at September 30, 2013. The difference in the rates for the third 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.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

Revenues

Oil and natural gas production. Oil and natural gas production for the nine months ended September 30, 2014 decreased to 2.1 MMBoe from 2.6 MMBoe for the nine months ended September 30, 2013. During the nine months ended September 30, 2014, natural gas production decreased 16% and oil production decreased 19%, resulting in a 17% decrease in Boe production as compared to the nine months ended September 30, 2013. Wells drilled during the last 12 months have predominantly been replacement wells for the wells that failed due to a formation collapse that led to the shearing of the casing in several of our Texas wells. The additional well drilled in the shallow waters offshore did not offset production declines from the more mature wells located in that area and in federal waters.

Total revenues. Total revenues for the nine months ended September 30, 2014 decreased to $99.8 million from $120.1 million for the nine months ended September 30, 2013. Natural gas revenues (exclusive of derivatives) increased $0.7 million or 1% due to higher natural gas prices offsetting lower natural gas production for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013. Natural gas prices increased by 21% period over period, to an average price of $5.06 for the nine months ended September 30, 2014 from an average natural gas price of $4.19 for the nine months ended September 30, 2013.

Oil revenues (exclusive of derivatives) decreased $19.3 million or 26%, as compared to the prior year period due to lower oil volumes and lower oil prices. The average oil price of $101.05 for the nine months ended September 30, 2014 represented an 8% decrease from the average oil price of $109.77 for the nine months ended September 30, 2013.

Operating costs and expenses

Production and delivery costs. Production and delivery costs for the nine months ended September 30, 2014 decreased to $20.2 million from $23.2 million for the same period in 2013. Production and delivery costs per Boe increased to $9.44 per Boe for the nine months ended September 30, 2014 from $9.00 per Boe for the same period in 2013 primarily as a result of decreased oil and natural gas production described above in the first nine months of 2014. During 2014 the Company also experienced lower contract pumping services, insurance, lift boat and labor costs than those during the same period in 2013.

Production taxes. Production taxes were $6.0 million for the nine months ended September 30, 2014, and $5.9 million for the comparable period in 2013. The Company pays production taxes to state governments at rates specified by geographic location and commodity. Production taxes on gas increased by $0.5 million due to higher natural gas prices for the nine months ended September 30, 2014 while production taxes on oil decreased by $0.4 million due to lower oil prices for the nine months ended September 30, 2014.

Workover costs. Workover costs for the nine months ended September 30, 2014 decreased to $2.1 million from $2.6 million for the same period in 2013. Workovers are performed on wells that need certain mechanical changes or enhancements to maintain or increase production. Due to fewer mechanical needs during the first nine months of 2014, the Company performed fewer workovers in that period than were necessary during the same period in 2013. Also, workover projects performed during the first nine months of 2014 had lower equipment rental, lift boat and transportation costs than those performed during the same period of 2013.

Depreciation, depletion and amortization. Depreciation, depletion and amortization for the nine months ended September 30, 2014 decreased to $58.9 million from $346.3 million for the nine months ended September 30, 2013. Excluding the effects of the ceiling test write-down in each period depreciation, depletion and amortization for the nine months ended September 30, 2014 decreased to $24.84 per Boe down from $26.91 per Boe for the nine months ended September 30, 2013. The decrease in depreciation, depletion and amortization was primarily due to a $276.9 million ceiling test write-down to eliminate the proved reserves in the Ewing Bank 920 Project during the third quarter of 2013. The Company had ceiling test write-downs of $0.4 million in the third quarter of 2014 and $5.3 million in the second quarter of 2014. The depletion rates for the first three quarters of 2014 were higher than the depletion rates for the same periods in 2013 due to lower future gross revenues at March 31, 2014, June 30, 2014 and September 30, 2014 resulting from the effects of the downward revisions to eliminate the Ewing Banks 920 Project proved undeveloped reserves during the third quarter of 2013.

General and administrative expenses. General and administrative expenses decreased to $9.2 million for the nine months ended September 30, 2014 from $14.2 million for the nine months ended September 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 nine months of 2014 as compared to the same period of 2013.

Interest expense, net. Net interest expense increased to $24.6 million for the nine months ended September 30, 2014, from $22.4 million for the nine months ended September 30, 2013 because of higher average debt balances and higher average interest rates. Debt balances averaged $255.6 million and $250.0 million during the nine months ended September 30, 2014 and 2013, respectively. Effective annual interest rates averaged 12.4% and 11.7% during the nine months ended September 30, 2014 and 2013, respectively. In the first nine months of 2014, the Company had $250.0 million of senior secured notes outstanding with a 12.5% interest rate. On September 12, 2014, the Company also borrowed $85.0 million under its Term Loan Facility. At September 30, 2014 the effective interest rate was 7.5% on the Term Loan Facility. For additional information on the Term Loan Facility, see the “-Financing Facilities” below.

Income tax benefit. For the nine months ended September 30, 2014, the Company recorded an income tax benefit of $7.0 million as compared to an income tax benefit of $109.3 million for the nine months ended September 30, 2013. Income tax benefits recognized were the result of effective tax rate calculations of approximately 33.3% at September 30, 2014 and approximately 37.1% at September 30, 2013. The difference in the rates for the first nine months 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.

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 $54 million on capital expenditures during the first nine months of 2014. After obtaining new funding from the Term Loan Facility discussed later in this section, we have increased our capital budget for 2014 to $124 million, which is an approximate $60 million increase over earlier plans. 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 now approximately $124 million, of which approximately $54 million was expended in the first nine months of 2014. The Company expects the remaining capital budget of $70 million to consist of:

•

$5 million for geological and geophysical costs, including leasing;

•

$32 million for Louisiana state water drilling and development;

•

$8 million for Offshore Federal water drilling and development;

•

$12 million for Onshore conventional and development; and

•

$13 million for California drilling and development.

In addition to the capital expenditure budget presented above, the Company also expects to incur approximately $5 million of costs for plugging and abandonment activities during the fourth quarter of 2014. Asset retirement obligations expected to be settled over the next 12 months are classified as a current liability in the accompanying condensed consolidated balance sheet.

While we have budgeted $70 million for capital expenditures and $5 million for plugging and abandonment activities for the remainder of 2014, the ultimate amount of capital we will expend for the remainder of the year may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. Through the first nine months of 2014, our 2014 capital budget was funded by existing cash and cash flows from operations. For the remainder of 2014, our capital budget will be funded by existing cash and cash flow from operations.

Under certain of the Company’s leasing agreements, there are requirements to obtain surety bonds for the performance of abandonment activities when certain criteria are met. The Company is now required by the Bureau of Ocean Energy Management (“BOEM”) to obtain these surety bonds. On November 5, 2014, the Company entered into an escrow agreement to fund a portion of the ARO of the Company. The Company transferred approximately $10 million into the escrow account for plugging and abandonment work. This will be accounted for as restricted cash.

Consolidated Cash Flows

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


	Nine Months Ended September 30,
	2014			2013
*In thousands*
Net cash provided by operating activities	$	41,474		$	67,146
Net cash used in investing activities		(57,931	)		(74,039	)
Net cash provided by financing activities		78,070			167

Net increase (decrease) in cash and cash equivalents	$	61,613		$	(6,726	)

Cash flows provided by operating activities

Operating activities provided cash totaling $41.5 million during the nine months ended September 30, 2014 as compared to cash provided by operating activities of $67.1 million during the nine months ended September 30, 2013. The decrease in operating cash flows during the nine months ended September 30, 2014 was primarily due to the net loss recorded for the period, the increase in accounts and revenues receivable and the increase in settlements of asset retirement obligations.

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 $57.9 million during the nine months ended September 30, 2014 as compared to cash used in investing activities of $74.0 million during the same period in 2013. Cash used in investing activities during the nine months ended September 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 nine 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 nine month periods ended September 30, 2014 and 2013 are summarized in the following table (in thousands):


	Nine Months Ended September 30,
	2014		2013
Project Area
Federal	$	4,805	$	8,377
Shallow State Waters		10,998		37,019
Onshore Texas, Louisiana and Mississippi		24,431		36,425
California, Oklahoma and Mid-Continent		13,786		16,214

Total	$	54,020	$	98,035

Cash flows provided by financing activities

Financing activities provided cash totaling $78.1 million during the nine months ended September 30, 2014 as compared to cash provided by financing activities of $0.2 million during the same period in 2013. Cash flows provided by financing activities during the first nine months of 2014 consisted of $84.2 million of financing (net of original issue discount) obtained pursuant to a new credit agreement, $4.5 million of borrowings for our insurance premium financing, offset partially by payments of $4.6 million on borrowings and $2.7 million of deferred loan costs on the new financing. Cash flows provided by financing activities during the first nine months of 2013 consisted primarily of a $51.5 million issuance of New Additional Notes and $6.8 million in borrowings for our insurance premium financing offset by payments of $55.0 million on our revolving credit facility and other borrowings, $1.5 million of deferred bond costs and $1.6 million for shareholder dividends.

Off-Balance Sheet Arrangements

As of September 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. As required by our Fifth Amended and Restated Credit Agreement, our derivative counterparties are limited to our secured lenders, which helps to minimize any potential non-performance risk. All of our derivative transactions are settled based upon reported settlement prices on the NYMEX.

At September 30, 2014, on a Boe basis, commodity derivative instruments were in place covering approximately 50% of our projected oil and natural gas sales for 2014, approximately 43% of our projected oil and natural gas sales for 2015 and approximately 36% of our projected oil and natural gas sales for 2016. Approximately 49% of the our 2014 natural gas production, approximately 41% of our 2015 natural gas production, approximately 36% of our 2016 natural gas production, approximately 53% of our 2014 oil production, approximately 50% of our 2015 oil production, and approximately 37% of our 2016 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 September 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⁾		30,338	$	90.86
2015		22,338	$	89.44
2016		15,335	$	88.12

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

As of September 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⁾		501,663	$	4.05
2015		375,806	$	4.01

⁽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
2015		—	$	—		—	$	—
2016		240,397	$	4.73		—	$	—

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


	NYMEX Contract Price
	Sell Put				Buy Put
	Volume in MMBtus/Mo		Weighted Average Strike Price		Volume in MMBtus/Mo		Weighted Average Strike Price
Period
2015		316,430	$	3.50		—	$	—
2016		240,397	$	3.50		240,397	$	4.00

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.


Remaining Contract Term	Contract Type	Volume in MMBtus/ Month		NYMEX Strike Price
January 2015—March 2015	Swap		212,973	$	4.09
January 2016	Swap		81,354	$	4.02
January 2016—March 2016	Swap		120,675	$	4.10

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 its previous 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 previous 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 September 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 $250.6 million as of September 30, 2014.

Term Loan Facility

On September 12, 2014, the Company entered into the Fifth Amended and Restated Credit Agreement. The Fifth Amended and Restated Credit Agreement provides the Borrowers with an $85.0 million term loan facility (the “Term Loan Facility”) which is secured by a first lien on substantially all of the Borrowers’ and the Company’s real and personal property. As of September 30, 2014, $85.0 million was outstanding under the Term Loan Facility. The maturity date for the Term Loan Facility is the earlier of September 12, 2016 or 91 days prior to the maturity date of the Senior Secured Notes. The annual interest rate on the Term Loan Facility is 6.5%, plus the greater of the LIBOR rate for the interest period or 1%. At September 30, 2014, the interest rate was 7.5%. Interest is payable quarterly on September 30, December 31, March 31, and June 30 of each year, which commenced on September 30, 2014.

The proceeds of the term loans incurred under the Fifth Amended and Restated Credit Agreement were or will be used by the Subsidiaries to (a) repay all expenses, fees or indemnitees outstanding under the Fourth Amended and Restated Credit Agreement dated as of November 29, 2011, (b) finance capital expenditures associated with the Subsidiaries’ oil and gas properties, (c) provide working capital for the Company’s operations and (d) pay transaction fees and expenses incurred in connection with the transactions contemplated by the Fifth Amended and Restated Credit Agreement. The Fifth Amended and Restated Credit Agreement contains customary restrictions on, among other things the Company’s ability to incur debt, grant liens on their property, make dispositions or investments, enter into mergers or issue new securities, make distributions, enter into affiliate transactions, enter into hedging contracts, amend their organizational documents and create new subsidiaries. In addition, the Fifth Amended and Restated Credit Agreement requires the Borrowers and the Company to maintain the following financial covenants as defined in the agreement: (i) a minimum Current Ratio of 1.0:1.0 as of the end of each fiscal quarter, (ii) a maximum First Lien Leverage Ratio of 2.0:1.0 as of the end of each fiscal quarter for the four immediately preceding fiscal quarters and (iii) a minimum PDP Asset Coverage Ratio of 1.0:1.0 as of January 1, 2015 and 1.1:1.0 as of April 1, 2015, July 1, 2015, January 1, 2016 and July 1, 2016. As of September 30, 2014, the Company was in compliance with all of these debt covenants.

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 West Texas Intermediate (“WTI”) price for crude oil and spot market prices applicable to our United States natural gas production. Pricing for crude oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Hypothetical changes in commodity prices chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations. However, since it is not possible to accurately predict future changes in commodity prices, this hypothetical change may not necessarily be an indicator of probable future fluctuations. Based on our average daily production for the nine months ended September 30, 2014, our annual oil sales would increase or decrease by approximately $7.3 million for each $10.00 per barrel change in crude oil prices and our annual gas sales would increase or decrease by approximately $12.8 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 will be unable to meet the financial terms of such transactions. As required by our Fifth Amended and Restated Credit Agreement, our derivative counterparties are limited to our secured lenders, which helps to minimize any potential non-performance risk.

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 ($1.4 million at September 30, 2014) and the sale of our crude oil and natural gas production, which we market to energy marketing companies, refineries and transmission companies ($15.8 million in receivables at September 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 Term Loan Facility. There was $85.0 million outstanding under the Term Loan Facility at September 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 September 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 September 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 and an uncompensated taking of property 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 the breach of contract claim. On March 29, 2013, the Company filed an appeal of the grant of summary judgment in United States Court of Appeals for the Federal Circuit 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, the court of appeals affirmed the grant of summary judgment. 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. On October 17, 2014, the Company filed a Petition for a Writ of Certiorari with the Supreme Court of the United States seeking review of the court of appeals’ decision. The takings claim remains pending in the Court of Federal Claims.

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

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

November 13, 2014	By: RAAM Global Energy Company

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

Exhibit Index



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

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

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)).

10.2		Fifth Amended and Restated Credit Agreement, dated as of September 12, 2014, by and among RAAM Global Energy Company, Century Exploration New Orleans, LLC, Century Exploration Houston, LLC, Century Exploration Resources, LLC and Wilmington Trust, National Association, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.1 to the Form 8-K filed on September 16, 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 September 30, 2014 and December 31, 2013; (ii) our Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and 2013; (iii) our Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 and 2013; and (iv) the notes to our unaudited Condensed Consolidated Financial Statements.

*	Filed herewith.

**	Furnished herewith.

RAAM Global Energy Co 10-Q