UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.20549

Form 10-K

(MARK ONE)

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

For the fiscal year ended December 31, 2013

¨	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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes x No ¨

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 x

(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 x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

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

As of June 30, 2013, the registrant’s common stock was not, and currently is not, listed on an exchange and, therefore, the aggregate market value of the registrant’s common stock held by non-affiliates on such date cannot be reasonably determined.

As of March 28, 2014, there were 61,433 shares of common stock, $0.01 par value, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

None.

TABLE OF CONTENTS


	Page
Part I.
Item 1. Business		6
Item 1A. Risk Factors		27
Item 1B. Unresolved Staff Comments		42
Item 2. Properties		43
Item 3. Legal Proceedings		43
Item 4. Mine Safety Disclosures		43

Part II.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		44
Item 6. Selected Financial Data		45
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		46
Item 7A. Quantitative and Qualitative Disclosures about Market Risk		64
Item 8. Financial Statements and Supplementary Data		67
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		104
Item 9A. Controls and Procedures		104

Part III.
Item 10. Directors, Executive Officers and Corporate Governance		106
Item 11. Executive Compensation		109
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		119
Item 13. Certain Relationships and Related Transactions, and Director Independence		120
Item 14. Principal Accounting Fees and Services		123

Part IV.
Item 15. Exhibits and Financial Statement Schedules		124

SIGNATURES		125
Glossary of Oil and Natural Gas Terms		126

INDEX TO EXHIBITS		131

CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS

This annual report contains forward looking statements within the meaning of 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 annual 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 annual report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward looking statements, although not all forward looking statements contain such identifying words.

Forward looking statements may include statements that relate to, among other things, our:

•

forward looking reserve estimates;

•

future financial and operating performance and results;

•

business strategy and budgets;

•

market prices;

•

technology;

•

financial strategy;

•

amount, nature and timing of capital expenditures;

•

drilling of wells and the anticipated results thereof;

•

oil and natural gas reserves;

•

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.

These forward looking statements are based on management’s current beliefs, expectations and assumptions about future events, based on currently available information, as to the outcome and timing of future events. When considering forward looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this annual report.

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;

•

federal and state regulatory developments and approvals;

•

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;

•

down hole drilling and completion risks that are generally not recoverable from third parties or insurance;

•

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

•

weather conditions;

•

availability and cost of material and equipment;

•

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;

•

potential defects in title to our properties;

•

possible losses from future litigation;

•

environmental risks;

•

changes in interest rates;

•

developments in oil and natural gas-producing countries;

•

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

•

worldwide political and economic conditions.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see Part I, “Item 1A. Risk Factors.”

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

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

PART I

Item 1. Business

General

We are a privately held Delaware corporation engaged in the exploration, development, production, exploitation and acquisition of oil and natural gas properties. Our producing assets are located offshore in the Gulf of Mexico and onshore in Louisiana, Texas, Oklahoma and California.

We have traditionally focused on acquiring assets in and around the United States Gulf Coast. Over the last decade we have worked to diversify our asset base through the acquisition and development of both conventional onshore assets and long-lived unconventional resource plays that are capable of supporting sustainable growth. Our assets create a portfolio of production, resources and opportunities that are balanced between long-lived, dependable production and exploration and development opportunities, as well as both oil and gas prone areas. Current development projects are focused on three main areas: shallow waters offshore, onshore conventional assets in Texas and conventional and unconventional assets in California and the Mid-Continent area. We plan to continue to augment our United States Gulf Coast production, increase our proved reserves and the reserve life of our portfolio through the development of these unconventional assets.

At December 31, 2013, we had estimated total proved oil and natural gas reserves of 10,725 MMBoe (35% oil). For the year ended December 31, 2013, our net daily production averaged 9,210 Boepd, which generated revenue of $149.5 million.

Core Properties

Our core properties include assets offshore in the Gulf of Mexico in Louisiana state waters and United States federal waters, onshore conventional assets in Texas and Louisiana, and conventional and unconventional assets in Mid-continent areas and California.

Offshore

Gulf of Mexico — Louisiana State Waters. We commenced operations in the Breton Sound 53 Field in 1989 and currently operate 16 producing wells from 2 manned production platforms which we own. Average net daily production for the year ended December 31, 2013 was 3,857 Boepd. Our leasehold position encompassed 12,076 net acres with proved reserves of 4,055 MBoe at December 31, 2013. We have had a 77% drilling success rate in the Breton Sound 53 Field since 2000. Historical drilling success has been in the Uvig and Tex W zones above 10,500 feet and deeper in the Big Hum and Cris I zones.

Gulf of Mexico — Federal Waters. We commenced operations in the shallow water West Cameron 368 Field and Ship Shoal 154 Field in the United States federal waters in 1987 and 1990, respectively, and we currently own and operate 15 wells and 13 production platforms. Average net daily production for the year ended December 31, 2013 from the United States federal waters was 789 Boepd. Our leasehold position encompassed 28,667 net acres with proved reserves of 1,109 MBoe as of December 31, 2013.

Onshore

Gulf Coast. We currently operate 22 producing wells onshore along the Gulf Coast in Louisiana and Texas. Average net daily production for the year ended December 31, 2013 was 4,418 Boepd. Our leasehold position encompassed 24,616 net acres with proved reserves of 5,037 MBoe at December 31, 2013. In Texas, we have focused on the Eocene Yegua/Cook Mountain trend, which produces natural gas with high condensate yields. Average net daily production for the year ended December 31, 2013 was 4,209 Boepd from 19 producing wells. In Louisiana, we have focused on the Lower Miocene Atchafalaya Basin. Average net daily production for the year ended December 31, 2013 was 85 Boepd from 2 producing wells. In addition, we realized 124 Boepd of production for the year ended December 31, 2013 from one well in another area of Louisiana.

Other Resource Plays

Mid-Continent. Our leasehold position in the Mid-Continent area includes 27,264 net acres in Oklahoma, with proved reserves of 213MBoe at December 31, 2013 and average net daily production for the year ended December 31, 2013 of 59 Boepd from 11 producing wells. Our leasehold position in the Mid-Continent area also includes 4,967 net acres in the Tucumcari Basin in New Mexico and approximately 120,000 net acres in a new venture, which was leased during late 2013.

California. Our leasehold position in the San Joaquin Basin in California encompassed approximately 26,337 net acres with proved reserves of 311 MBoe at December 31, 2013 and average net daily production for the year ended December 31, 2013 of 87 Boepd from 3 producing wells. One of these wells was shut-in for the majority of 2013 and did not begin producing until the beginning of December 2013. During 2013, we drilled one additional well, which was not yet producing at yearend.

Our Operations

Proved Reserves

The following tables set forth our estimated proved crude oil and natural gas reserves and percent of total proved reserves that are proved developed as of December 31, 2013 by reserve category and region. Netherland, Sewell & Associates, Inc., independent petroleum engineers, evaluated properties representing approximately 98% of our proved reserves and Cawley, Gillespie & Associates, Inc., independent petroleum engineers, evaluated the remaining properties representing approximately 2% of our proved reserves at December 31, 2013. Our estimated proved reserves at December 31, 2013 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January 2013 through December 2013, without giving effect to derivative transactions, and were held constant throughout the life of the properties. These prices were $93.42 per Bbl for crude oil and oil equivalents and $3.67 per MMBtu for natural gas. These prices are adjusted for energy content, transportation fees, and regional price differentials resulting in weighted adjusted product prices for the proved reserves over the remaining lives of the properties of $98.10 per Bbl for crude oil and oil equivalents and $4.20 per MMBtu of gas.


	December 31, 2013
	Crude Oil		Natural Gas
	(MBbls)		(MMcf)
Estimated proved developed producing		1,971		24,277
Estimated proved developed non-producing		894		7,001
Estimated proved undeveloped		838		10,851
Total estimated proved reserves		3,703		42,129


	December 31, 2013
	Proved Developed				Proved Undeveloped
	Crude Oil		Natural Gas		Crude Oil		Natural Gas
	(MBbls)		(MMcf)		(MBbls)		(MMcf)
Offshore
Federal waters		907		502		109		58
Shallow state waters		1,069		13,024		453		2,174
Onshore
Texas and Louisiana		512		16,870		276		8,619
Resource Plays
Mid-Continent		84		773		—		—
California		293		109		—		—
Total		2,865		31,278		838		10,851

We have historically added reserves through our exploration program and development activities. Changes in proved reserves were as follows:


	December 31,
*In MBoe*	2013			2012			2011
Proved reserves beginning of year		25,044			23,459			18,779
Revisions of previous estimates		(13,337	)		1,249			3,676
Extensions, discoveries and other additions		3,268			4,508			4,992
Production		(3,362	)		(4,172	)		(3,988	)
Sales of reserves in place		(888	)		—			—
Proved reserves end of year		10,725			25,044			23,459

Revisions. Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs. Downward revisions of 13,337 MBoe during 2013 were primarily a result of the elimination of the Ewing Banks 920 (“EB 920” or “Flatt’s Guitar”) Project proved undeveloped reserves. During September 2013, the Company determined that it could not meet the financial certifications required to obtain permits to develop its offshore EB 920 Project in the Gulf of Mexico, due in large part to the substantially increased Worst Case Discharge (“WCD”) assumptions imposed by the Bureau of Ocean Energy Management (“BOEM”). As a result, the proved undeveloped reserves associated with the EB 920 Project no longer met the requirements of reasonable certainty to remain booked as proved reserves at the end of the third quarter of 2013. These reserves accounted for approximately 63% of the total revision. The Company also had downward revisions due to the formation collapse in some of the wells in the Yegua Trend in East Texas. These revisions accounted for approximately 16% of the total revision. The revisions also included downward revisions based on management’s decision during the fourth quarter of 2013 not to drill certain proved undeveloped reserves in the Oklahoma area that had previously been booked. These reserves accounted for approximately 15% of the total revision. Revisions of 1,249 MBoe during 2012 mainly include downward revisions in wells drilled in the shallow waters of Louisiana and upward revisions in wells located onshore Texas and in federal waters. Revisions of 3,676 MBoe during 2011 include additions due to additional production history for our wells drilled onshore in Texas and in the shallow waters of Louisiana.

Extensions, discoveries and other additions. These are additions to proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. During 2013, we had extensions and discoveries of 3,268 MBoe mainly due to new wells drilled in the Yegua Trend of East Texas. During 2012, we had extensions and discoveries of 4,508 MBoe mainly due to new wells drilled onshore in Texas and Oklahoma. During 2011, we had extensions and discoveries of 4,992 MBoe due

to new wells drilled onshore in Texas, due to new wells drilled in the shallow waters in Louisiana and due to a well drilled in California.

We expect that a significant portion of future reserve additions will come from our major development projects including the extension and further development of the Breton Sound 53 Field, the expansion of the Eocene Yegua/Cook Mountain producing trend in East Texas, the extension and further development of the Midcontinent area. We may also purchase proved properties in strategic acquisitions.

Technology used to establish proved reserves. Under the Securities and Exchange Commission (“SEC”) rules, proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, our internal reserve engineers and Netherland, Sewell & Associates, Inc. and Cawley, Gillespie & Associates, Inc., our independent petroleum engineers, employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves, material balance calculation or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using pore volume calculations and performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

Qualifications of technical persons and internal controls over reserves estimation process. During 2013, we used the services of two independent petroleum engineering firms: Netherland, Sewell & Associates, Inc. and Cawley, Gillespie & Associates, Inc. (“Independent Engineers”). In accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and guidelines established by the SEC, our Independent Engineers estimated 100% of our proved reserve information as of December 31, 2013 included in this annual report. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultants to ensure the integrity, accuracy and timeliness of data furnished the Independent Engineers in their reserves estimation process. Our technical team meets regularly with representatives of the Independent Engineers to review properties and discuss methods and assumptions used in the Independent Engineers’ preparation of the year-end reserves estimates. All field and reserve technical information, which is updated annually, is assessed for validity when the Independent Engineers hold technical meetings with our internal staff of petroleum engineers, operations and land personnel to discuss field performance and to validate future development plans. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a copy of the Independent Engineers’ reserve reports are reviewed with representatives of each Independent Engineer, respectively, and our internal technical staff before dissemination of the information. Additionally, our senior management reviews and approves the Independent Engineers’ reserve reports and any internally estimated significant changes to our proved reserves on a quarterly basis.

Our Vice President of Reservoir Engineering is the technical person primarily responsible for overseeing the preparation of our reserves estimates. He has a BS degree in Civil Engineering and an MBA in Finance. He has

over 30 years of industry experience with positions of increasing responsibility in operations, acquisitions, engineering and evaluations. He has worked in the area of reserves and reservoir engineering since 1985 and is a member of the Society of Petroleum Engineers and Society of Petroleum Evaluation Engineers. He is a registered Professional Engineer in the State of Louisiana. Our Vice President of Reservoir Engineering reports directly to our Senior Vice President of Exploration and our Chief Operating Officer. Reserves estimates are reviewed and approved by senior engineering staff with final approval by our Chief Operating Officer and certain other members of senior management.

Within Netherland, Sewell & Associates, Inc., the technical persons primarily responsible for preparing the estimates set forth in the Netherland, Sewell & Associates, Inc. summary reserve report filed herewith are Mr. James E. Ball and Mr. David J. Ryan. Mr. Ball has been practicing consulting petroleum engineering at Netherland, Sewell & Associates, Inc. since 1998. Mr. Ball is a Licensed Professional Engineer in the State of Texas (License No. 57700) and has over 32 years of practical experience in petroleum engineering, with over 25 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1980 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Ryan has been practicing consulting petroleum geology at Netherland, Sewell & Associates, Inc. since 1998. Mr. Ryan is a Certified Petroleum Geologist in the State of Texas (License No. 3868) and has over 26 years of practical experience in petroleum geosciences, with over 18 years of experience in the estimation and evaluation of reserves. He graduated from Central Michigan University with Bachelor Degrees in Geology, Earth Science, and Biology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Within Cawley, Gillespie & Associates, the technical person primarily responsible for preparing the estimates set forth in the RAAM Global Energy Company December 31, 2013 summary reserve report filed herewith is Mr. Bob Ravnaas. Mr. Bob Ravnaas is a Licensed Professional Engineer in the State of Texas (License No. 61304) and has thirty years of experience in the evaluation of oil and gas reserves. He holds a Bachelor of Science Degree in Chemical Engineering from the University of Colorado and a Masters Degree in Petroleum Engineering from the University of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

Within Cawley, Gillespie & Associates, the other technical person responsible for preparing the estimates set forth in the RAAM Global Energy Company December 31, 2013 summary reserve report filed herewith is Mrs. Kellie Jordan. Mrs. Jordan has over eight years of experience in the evaluation of oil and gas reserves. She holds a Bachelor of Science Degree in Petroleum Engineering from the University of Texas. She is also a member of the Society of Petroleum Engineers.

Proved undeveloped reserves. Our proved undeveloped reserves at December 31, 2013 were 2.6 MMBoe down from 11.7 MMBoe at December 31, 2012. Our proved undeveloped reserves consisted of 0.8 MMBbls of crude oil at December 31, 2013 down from 9.8 MMBbls at December 31, 2012 and 10.8 Bcf of natural gas at December 31, 2013 down from 11.8 Bcf of natural gas at December 31, 2012. During September 2013, the Company determined that it could not meet the financial certifications required to obtain permits to develop its offshore EB 920 Project in the Gulf of Mexico, due in large part to the substantially increased WCD assumptions imposed by the BOEM. As a result, the proved undeveloped reserves associated with the EB 920 Project no longer met the requirements of reasonable certainty to remain booked as proved reserves at the end of the third quarter of 2013. These reserves had previously accounted for 71.2% of our proved undeveloped reserves at December 31, 2012. In addition, during the fourth quarter of 2013 management determined that it would not drill certain proved undeveloped reserves located in Oklahoma, which had accounted for approximately 14.0% of our proved undeveloped reserves at December 31, 2012. The largest increase in proved undeveloped reserves during 2013 was the result of drilling activities in the Yegua Trend of East Texas. Other areas which saw modest increases were in the federal waters offshore and shallow waters offshore in Louisiana. Estimated future development costs relating to the development of 2013 year-end proved undeveloped reserves, as shown in our December 31, 2013 reserve report, is $29.7 million, of which 2014 and 2015 expenditures are estimated to be $21.7 million and zero, respectively. All proved undeveloped reserves are scheduled to be drilled by 2018.

Capital Expenditure Budget

We have a total capital expenditure budget of $82 million for 2014, which is a 35% decrease over the $126 million invested during 2013. 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.

The 2014 capital budget consists of:

•

$19 million for geological and geophysical costs, including leasing;

•

$24 million for Louisiana state water drilling and development;

•

$10 million for onshore conventional drilling and development;

•

$10 million for California drilling and development;

•

$15 million for projects in progress; recompletions; and

•

$4 million for new ventures to be developed.

While we have budgeted $82 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling results as the year progresses. To date, our 2014 capital budget has been funded from our cash flows from operations.

We currently expect that our remaining 2014 capital expenditures will be funded from our cash flow from operations in 2014, which includes projected cash flow from new wells, and proceeds from the sales of non-core assets. Although the Company has no current plans to use the Amended Revolving Credit Facility to fund capital expenditures, if our cash flows from operations in the remainder of 2014 and the proceeds from sales of non-core assets are not sufficient to meet our capital expenditure requirements, the Company could use the Amended Revolving Credit Facility to fund any deficiency in order to continue its exploration and development activities.

For additional information please see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

Developed and Undeveloped Acreage

The following table presents the total gross and net developed and undeveloped acreage by region as of December 31, 2013:


	Developed acres				Undeveloped acres				Total
	Gross		Net		Gross		Net		Gross		Net
Offshore
Federal waters(1)		13,359		12,696		16,520		15,971		29,879		28,667
Shallow waters(2)		10,865		8,852		3,266		3,224		14,131		12,076
Onshore
Texas and Louisiana(3)		5,951		4,272		33,915		20,344		39,866		24,616
Resource Plays
California		800		800		32,429		25,537		33,229		26,337
Mid-Continent		5,760		2,304		224,709		149,835		230,469		152,139
Total		36,735		28,924		310,839		214,911		347,574		243,835

(1)	Our core areas of production in the United States federal waters in the Gulf of Mexico are the West Cameron 368 Field and the Ship Shoal 154 Field.

(2)	Our core area of production in the state waters in the Gulf of Mexico is in the Breton Sound 53 Field.

(3)	Our core areas of production in Texas are the Eocene Yegua/Cook Mountain trend and our core areas of production in Louisiana are in the Lower Miocene trend.

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2013 that will expire over the next three years by region unless production is established within the spacing units covering the acreage prior to the expiration dates:


	2014				2015				2016
	Gross		Net		Gross		Net		Gross		Net
Offshore
Federal waters		11,520		10,971		5,000		5,000		—		—
Shallow waters		—		—		2,746		2,746		—		—
Onshore
Texas and Louisiana		19,889		12,115		3,671		3,341		5,202		2,015
Resource Plays
California		2,859		1,062		11,838		9,321		14,697		10,383
Mid-Continent		76,609		27,176		17,892		3,089		553		67
Total		110,877		51,324		41,147		23,497		20,452		12,465

We have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three to five years. As is customary in the oil and natural gas industry, we can retain our interest in undeveloped acreage by commencing drilling activity that establishes commercial production sufficient to maintain the leases or by payment of delay rentals during the primary term of such leases. We do not assign proved undeveloped reserves to leases after their expiration. Of the 51,324 net acres expiring in 2014, we are currently focusing on developing 340 net acres expiring in California. Our current plan in the other areas is to let the acres scheduled for expiration in 2014 expire.

Drilling Activity

During the three years ended December 31, 2013, we drilled exploratory and development wells as set forth in the table below:


	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells
Oil		—		—		6.0		2.3		8.0		3.2
Natural Gas		—		—		4.0		2.2		3.0		2.2
Dry		1.0		0.7		2.0		1.7		2.0		2.0
Total Exploratory Wells		1.0		0.7		12.0		6.2		13.0		7.4
Development Wells
Oil		1.0		1.0		15.0		6.1		—		—
Natural Gas		6.0		4.0		4.0		2.8		2.0		1.5
Dry		—		—		—		—		—		—
Total Development Wells		7.0		5.0		19.0		8.9		2.0		1.5
Total Wells		8.0		5.7		31.0		15.1		15.0		8.9

Our rig activity during 2014 will be dependent on crude oil and natural gas prices, and, accordingly, our rig count may increase or decrease from current levels. There can be no assurance, however, that additional rigs will be available to us at an attractive cost. During the first quarter of 2014, we had two rigs drilling in the Texas Yegua Trend.

Summary of Oil and Natural Gas Properties and Projects Offshore

We operated 22 offshore production platforms with 31 producing wells as of December 31, 2013. Production from our offshore assets averaged 4,646 Boepd for the year ended December 31, 2013. Our offshore staff includes 3 explorationists who generate prospects from our extensive, modern 3-D seismic database. Our offshore operations cover three core areas of production in the Gulf of Mexico: (1) the West Cameron 368 Field production area in shallow United States federal waters, (2) the Ship Shoal production area in shallow United States federal waters, and (3) the Breton Sound production area in shallow state waters. In each of these core areas, we have platforms, production facilities, and pipelines in place, where production from new wells can be established quickly. We have a significant inventory of drilling prospects in each of these core areas. In the United States federal waters, we hold 12,696 net acres by production and we have 15,971 net acres that remain undrilled in primary term contracts. In the state waters of Louisiana, we hold 8,852 net acres by production.

West Cameron 368 Field. The West Cameron 368 Field was one of our first discoveries in the Gulf of Mexico. We have drilled 22 successful wells out of 24 wells drilled and have produced over an aggregate gross 120 Bcf and 1.0 MMBbls since our first discovery in 1986. West Cameron 368 Field represented 4% of our average daily production for the year ended December 31, 2013.

Ship Shoal 154 Field. In 1989, we farmed out Ship Shoal 150 Block from Chevron. In 1990, we drilled our first successful well on this prolific salt dome. We have drilled 17 wells based on our 3-D seismic analysis and we have completed 11 of these wells as commercial oil producers. We have produced over an aggregate gross 8.8 Bcf and 11.9 MMBbls to date from Ship Shoal. Ship Shoal 154 Field represented 5% of our average daily production for the year ended December 31, 2013.

Breton Sound 53 Field. The Breton Sound 53 Field has been a core area for our offshore operations since we first acquired and completed the Virgo BS 52 SL 12806 Century #1 well in 1989. This well established the first geopressured production in the Breton Sound 53 Field, which has subsequently grown to become the Company’s most prolific offshore field to date. We have 12,076 net acres under lease and operate two manned production platforms in the Breton Sound 53 Field. The Breton Sound 53 Field represented 42% of our average daily production for the year ended December 31, 2013. We drilled one development well in this area during 2013.

Onshore

Production from our onshore properties in the Gulf Coast averaged 4,418 Boepd for the year ended December 31, 2013.

Eocene Yegua/Cook Mountain. During 2013, we continued our onshore drilling program. The Eocene Yegua/Cook Mountain trend in southeast Texas has been a core area for us since 2005. We performed 3-D seismic of the 167 square mile JASPO proprietary in 2005 and have since merged this data with over 300 square miles of licensed 3-D data. Production from this area averaged 4,209 Boepd for the year ended December 31, 2013. The Eocene Yegua/Cook Mountain trend represented 46% of our average daily production for the year ended December 31, 2013. We drilled and completed five successful wells in this area during 2013 and placed three wells drilled during 2012 into production resulting in a total of 21 wells producing in this area during 2013. We were also in the process of drilling one additional well year-end.

Resource

We have significant land positions in California and the Mid-Continent, which are in various states of development.

California — San Joaquin Basin (Conventional and Unconventional). We have established an office in Bakersfield, California and have begun a major exploration program in the San Joaquin Basin. The program is focusing on both conventional and unconventional plays. We have acquired 3-D and 2-D seismic data over the prospective area. We have 26,337 net acres under lease as of December 31, 2013. During 2013, we drilled one new well in this area, which was not yet producing at yearend. Our average net daily production was 87 Boepd with estimated proved reserves of 311 Mboe.

Mid-Continent. During the fourth quarter of 2013, the Company sold approximately 62,000 net acres in oil, gas and/or mineral leases located in Texas and Colorado. The Company also sold approximately 34,000 net acres in oil, gas and/or mineral leases located in Oklahoma. The acres sold in Oklahoma represented 3.6% of the Company’s reserves as of December 31, 2012. The acreage sold in Texas and Colorado did not have proved reserves associated with it. The Company received $51.6 million in cash consideration, which it plans to use for capital expenditures.

The Company has selected its next unconventional play, which is located in the Mid-Continent area, and leased approximately 120,000 net acres. It is the Company’s intention to seek a joint venture partner on this play.

We currently have 4,967 net acres in a joint venture in the Tucumcari Basin in New Mexico. We own an 18.75% working interest in this project. As this is a dry gas play, we have no plans for any activities in 2014.

Production, Price and Cost History

Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. During 2013, our gas prices, exclusive of hedges, have been higher than last year due to a general increase in gas market prices. At year-end, we started seeing the potential of large draws in storage due to the cold weather which has engulfed most of the country and we find ourselves in early 2014 with lower storage balances than we have seen in the past five years. During 2013, our oil prices have continued to be strong even though the premium on our Light and Heavy Louisiana Sweet barrels has diminished. Both oil and gas prices have moderated due to modest improvements in our economy, along with a cold winter. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect such volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets.

The following table sets forth information regarding oil and natural gas production, revenues and realized prices and production costs for the years ended December 31, 2013, 2012 and 2011. For additional information on price calculations, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	Year Ended December 31,
	2013		2012		2011
Net production volumes:
Oil (Bbl)		884,994		1,103,653		1,050,092
Natural gas (Boe)		2,476,557		3,068,547		2,938,407
Oil equivalents (Boe)		3,361,551		4,172,200		3,988,499
Average sales price per unit:(1)
Oil (Bbl)	$	103.52	$	108.28	$	108.30
Natural gas (Mcf)	$	4.24	$	3.45	$	4.94
Oil equivalents (Boe)	$	45.98	$	43.87	$	50.34
Costs and expenses per Boe:
Lease operating expenses	$	10.41	$	8.52	$	8.61
Depreciation, depletion and amortization(2)	$	126.75	$	28.29	$	17.99
General and administrative expenses	$	6.35	$	4.98	$	7.03

(1)	Average prices presented do not give effect to our derivative transactions. Please see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Oil and Gas Derivatives” for a discussion of our derivative activities.

(2)	Depreciation, depletion and amortization for the years ended December 31, 2013 and 2012 was $26.77 and $19.43 per Boe excluding the ceiling test write-downs, respectively. There were no ceiling test write-downs during 2011.

Net production volumes for the year ended December 31, 2013 were 3,362 MBoe, a 19% decrease from net production of 4,172 MBoe for 2012. Our net production volumes decreased by 810 MBoe over 2012 net production volumes mainly due to casing failures in several wells in the Yegua Trend, which went offline during the late second quarter of 2013 and required new wells to be drilled. The casing failures were due to a formation collapse resulting from the normal decrease in formation pressure as the field was produced. Our average oil sales prices decreased $4.76 per Bbl to $103.52 per Bbl for the year ended December 31, 2013 from $108.28 per Bbl for the year ended December 31, 2012. Our average gas sales prices increased $0.79 per Mcf to $4.24 per Mcf for the year ended December 31, 2013 from $3.45 per Mcf for the year ended December 31, 2012. Our production and delivery costs increased $1.89 per Boe, or 22.3%, to $10.41 per BOE for the year ended December 31, 2013 from $8.52 per Boe for the year ended December 31, 2012 mainly due to the decrease in production. The total production and delivery costs decreased to $35.0 million for the year ended December 31, 2013 from $35.5 million for the year ended December 31, 2012. The overall decrease in production and delivery costs was primarily attributable to lower costs for boat transportation, Safety and Environmental Management System (SEMS) compliance efforts and supplies and tools.

Net production volumes for the year ended December 31, 2012 were 4,172 MBoe, a 5% increase from net production of 3,988 MBoe for 2011. Our net production volumes increased 184 MBoe over 2011 net production volumes mainly due to the successful drilling and completion of onshore wells in Texas and onshore wells in California. Our average oil sales prices decreased $.02 per Bbl to $108.28 per Bbl for the year ended December 31, 2012 from $108.30 per Bbl for the year ended December 31, 2011. Our average gas sales prices decreased $1.49 per mcf to $3.45 per Mcf for the year ended December 31, 2012 from $4.94 per Mcf for the year ended December 31, 2011. Our production and delivery costs decreased $0.09 per Boe, or 1.0%, to $8.52 per Boe for the year ended December 31, 2012 from $8.61 per Boe for the year ended December 31, 2011 mainly due to new onshore production.

The following table sets forth information regarding our average net daily production for the years ended December 31, 2013 and 2012:


	Average Net Daily Production for the Year Ended December 31, 2013						Average Net Daily Production for the Year Ended December 31, 2012
	Bbls		Mcf		Boe		Bbls		Mcf		Boe
Offshore
Federal waters(1)		410		2,274		789		555		4,968		1,383
State waters(2)		909		17,690		3,857		1,047		21,784		4,678
Onshore
Texas, Louisiana and Mississippi(3)		988		20,579		4,418		1,111		23,125		4,965
Resource Plays
Mid-Continent and California		118		168		146		302		427		373
Total		2,425		40,711		9,210		3,015		50,304		11,399

(1)	Our core areas of production in the United States federal waters in the Gulf of Mexico are the West Cameron 368 Field and the Ship Shoal 154 Field.

(2)	Our core area of production in the state waters in the Gulf of Mexico is in the Breton Sound 53 Field.

(3)	Our core areas of production in Texas are the Eocene Yegua/Cook Mountain trend and our core areas of production in Louisiana are in the Lower Miocene trend.

Productive Wells

The following table presents the total gross and net productive wells by project area and by oil or gas completion as of December 31, 2013:


	Oil Wells				Natural Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Offshore
Federal waters(1)		12.0		9.3		3.0		2.7		15.0		12.0
State waters(2)		5.0		3.1		11.0		9.6		16.0		12.7
Onshore
Texas and Louisiana(3)		4.0		2.3		18.0		11.9		22.0		14.2
Resource Plays
Mid-Continent and California		14.0		8.8		—		—		14.0		8.8
Total		35.0		23.5		32.0		24.2		67.0		47.7

(1)	Our core areas of production in the United States federal waters in the Gulf of Mexico are the West Cameron 368 Field and the Ship Shoal 154 Field.

(2)	Our core area of production in the state waters in the Gulf of Mexico is in the Breton Sound 53 Field.

(3)	Our core areas of production in Texas are the Eocene Yegua/Cook Mountain trend and our core areas of production in Louisiana are in the Lower Miocene trend.

Gross wells are the number of wells in which a working interest is owned and net wells are the total of our fractional working interests owned in gross wells.

Marketing and Customers

We generally sell our natural gas and oil at the wellhead to marketing companies. All of our offshore and shallow water production and onshore gas production is connected to a pipeline. Generally our onshore oil production is stored in tanks and delivered to market by trucks.

We have been selling to our customers set forth below for over ten years and believe that we receive market rates for our natural gas and oil production from such customers. We obtain letters of credit from our customers and discuss the credit worthiness of our customers’ purchasers on an ongoing basis.

We sold natural gas and oil production representing 10% or more of our natural gas and oil revenues for the years ended December 31, 2013, 2012 and 2011 to four customers. In the exploration, development, and production business, production is normally sold to relatively few customers. However, based on the current demand for natural gas and oil, management believes that the loss of any major customers would not have a material adverse effect on operations.

Delivery Commitments

In order to get better pricing from our intrastate markets, we have committed gas production for several of our onshore properties to various purchasers. Most of our wells located onshore in Texas have gas commitments. These commitments range through March 31, 2014, February 28, 2015, and September 30, 2015 and represent 18%, 13% and 13%, respectively, of our production during December 2013. Our gas production in Oklahoma, which is less than 1% of our production, has a life of lease commitment. Our gas that is sold in California has a commitment through April 30, 2016. This also represents less than 1% of our production. The remaining gas production is being sold pursuant to month-to-month marketing arrangements which require either a 30 day or 60 day termination notice by both parties. All of our oil is being sold pursuant to month-to-month marketing contracts that are terminable by either party with a 30 day notice. None of the commitments have required minimum daily production volumes.

Competition

We encounter intense competition from other oil and natural gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies and individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources who have been engaged in the oil and natural gas business for much longer than us. These companies may be able to pay more for productive oil and natural gas properties, exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

Intellectual Property

The majority of the Company’s 3-D seismic data is licensed from the owners of the data under long-term, non-exclusive agreements. These licenses range in term from 25 to 50 years. At times, licensed 3-D data is re-processed on a proprietary basis by the Company. This reprocessed data is uniquely controlled by the Company, but is still subject to the underlying license agreements, with the Company having no ownership rights. The Company is a majority owner of the JASPO 3-D survey and the Rivers Edge 3-D covering certain lands in the upper Texas Gulf Coast. Several successful wells have been drilled on the JASPO 3-D survey. The Rivers Edge 3-D is an extension of and adjacent to the JASPO 3-D and will be the focus of our exploration activities in the Texas Yegua Trend in 2014. The Company does not have any current plans to sell its ownership in these surveys, but may grant non-exclusive licenses to third parties in the future.

Employees

As of December 31, 2013, we had 69 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good. From time to time, we utilize the services of independent contractors to perform various field and other services.

Title to Properties

As is customary in the oil and gas industry, we initially conduct a preliminary review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties; we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our revolving credit facility, liens for current taxes and other burdens which we believe do not materially interfere with the use or affect our carrying value of the properties.

Seasonality

In the past, the demand for and price of natural gas has increased during the winter months and decreased during the summer months. However, these seasonal fluctuations were somewhat reduced because during the summer, pipeline companies, utilities, local distribution companies and industrial users purchase and place into storage facilities a portion of their anticipated winter requirements of natural gas. With the development of the shale plays, seasonality is less a factor. Oil was also impacted by generally higher prices during winter months but has more recently been affected by geopolitical events and the global recession. Seasonal weather changes have also affected our operations. Tropical storms and hurricanes occur in the Gulf of Mexico during the summer and fall, which may require us to evacuate personnel and shut-in production until these storms subside. Also, periodic storms during the winter often impede our ability to safely load, unload and transport personnel and equipment, which delays the installation of production facilities, thereby delaying sales of our oil and natural gas.

Environmental and Occupational Health and Safety Matters

Our exploration, development and production operations are subject to various federal, regional, state and local laws and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and gas drilling and production; restrict the way we handle or dispose of our wastes; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; impose specific health and safety criteria addressing worker protection; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or new interpretations of enforcement policies that result in more stringent and costly well construction, drilling, water management or completion activities, or waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on our financial condition or results of operations, we cannot provide any assurance that we will be able to remain in compliance in the future

with respect to existing or new laws and regulations or the terms and conditions required of necessary permits or that such future compliance will not have a material adverse effect on our business and operating results.

The following is a summary of some of the more significant existing environmental and occupational health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Wastes

The federal Comprehensive Environmental Response, Compensation, and Liability Act, as amended (the “CERCLA”), also known as the “Superfund” law, and comparable state statutes impose joint and several liability without regard to fault or legality of the original conduct, on certain classes of persons considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current and past owners or operators of a site where the release occurred and anyone who transported or disposed or arranged for the transport or disposal of a hazardous substance found at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency (“EPA”) and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the responsible classes of persons the costs of such action. Many states have adopted comparable or more stringent state statutes. Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substances.

The federal Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of nonhazardous and hazardous solid wastes. Under the auspices of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although a substantial amount of the drilling fluids, produced waters and most other wastes associated with the exploration, development and production of oil or natural gas, if properly handled, are exempt from regulation as hazardous wastes under RCRA and instead are regulated under less stringent nonhazardous waste provisions of RCRA, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of nonhazardous waste or categorize some nonhazardous waste as hazardous in the future. Any repeal or modification of this exception or similar exceptions under state law could result in an increase in our costs to manage and dispose of generated waste, which could have a material adverse effect on our results of operations and financial position. In the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for recycling or disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to RCRA, CERCLA and analogous state laws. Under these laws, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination caused by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

Water Discharges and Subsurface Injections

The federal Water Pollution Control Act, as amended (the “Clean Water Act”), and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an

analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for noncompliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and costs.

Our oil and natural gas exploration and production operations generate produced water, drilling muds, and other waste streams, some of which may be disposed via injection in underground wells situated in non-producing subsurface formations. The disposal of oil and natural gas wastes into underground injection wells are subject to the Safe Drinking Water Act, as amended (the “SDWA”), and analogous state laws. The Underground Injection Well Program under the SDWA requires that we obtain permits from the EPA or analogous state agencies for our disposal wells, establishes minimum standards for injection well operations, restricts the types and quantities that may be injected, and prohibits the migration of fluid containing any contaminants into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource, and imposition of liability by third parties for alternative water supplies, property damages and personal injuries. While we believe that we have obtained the necessary permits from the applicable regulatory agencies for our underground injection wells and that we are in substantial compliance with applicable permit conditions and federal and state rules, any changes in the laws or regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of produced waters and ultimately increase the cost of our operations, which costs could be significant. Furthermore, in response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to conduct continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position.

Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in many of our drilling and completion programs. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and issued revised permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency continues to project the issuance of a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states, including Louisiana, Texas, Oklahoma and California, where we conduct operations, have adopted or are considering adopting legal requirements that could impose more stringent permitting, disclosure, or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or

curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells. For example, concerns related to hydraulic fracturing activities in California have led to the state legislature proposing bans and other measures restricting hydraulic fracturing, and operators are reportedly experiencing delays in obtaining permits to drill new wells while the state oil and gas agency promulgates new regulations related to hydraulic fracturing fluid chemical additive disclosure, water management and groundwater protection.

In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review in 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards in 2014. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods and issued a report in 2011 on immediate and longer-term actions that may be taken to reduce environmental and safety risks of shale gas development. Also, in May 2013, the federal Bureau of Land Management published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used in hydraulic fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

Releases of Oil

The primary federal law for oil spill liability is the Oil Pollution Act, as amended (the “OPA”), which amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters, including the Outer Continental Shelf (“OCS”) or adjoining shorelines. A liable “responsible party” includes the owner or operator of an onshore facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several, strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages including the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to $150 million in certain situations. If there were to occur an oil discharge or substantial threat of discharge, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position. Moreover, as a result of the Deepwater Horizon incident, legislation was proposed in a prior session of Congress to increase the minimum level of financial responsibility to $300 million. While the legislation failed to pass, it is possible that similar legislation could be introduced in the future; if such proposed legislation were adopted, we could experience difficulty in providing financial assurances sufficient to comply with this requirement, in which event, we could be forced to sell our properties or operations located on the OCS or enter into partnerships with other companies that can meet the increased financial responsibility requirement. Such developments also could have an adverse effect on the value of our offshore assets and the results of our operations.

Air Emissions

The federal Clean Air Act (“CAA”), as amended, and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. For example, in 2012, the EPA published final rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare. However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. We believe we are in substantial compliance with the requirements of these new regulations.

Climate Change

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted regulations to restrict emissions of greenhouse gases under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews of certain large stationary sources. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified sources in the United States, including, among others, certain onshore and offshore oil and natural gas production facilities, on an annual basis. Certain of our oil and natural gas operations are subject to such greenhouse gas reporting requirements, and we monitor our emissions to make such required reports when due.

While Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing greenhouse gas emissions by means of cap and trade programs that typically require major sources of greenhouse gas emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those greenhouse gases. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact the Company’s business, any such future laws and regulations that require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.

Activities on Federal Lands

Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (the “NEPA”) which requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.

Endangered Species Act Considerations

The federal Endangered Species Act, as amended (the “ESA”), restricts activities that may affect endangered and threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. If endangered species are located in areas of the underlying properties where we wish to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of numerous species as endangered or threatened under the ESA before the completion of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures, time delays, or could result in limitations on our exploration and production activities, and any one or more of these developments could have an adverse impact on our ability to develop and produce reserves.

Employee Health and Safety

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right–to–know regulations under the Title III of CERCLA and similar state statutes require that we organize and maintain information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

We believe that we are in substantial compliance with all existing environmental and occupational health and safety laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation or pollution control activities for the years ended December 31, 2013, 2012 and 2011. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2014 or that will otherwise have a material impact on our financial position or results of operations in the future. However, we cannot assure you that the passage of more stringent laws and regulations in the future will not have a negative impact on our business activities, financial condition or results of operations.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the

location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission, or FERC, and the courts. We cannot predict when or whether any such proposals may become effective.

Drilling and Production

Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulations include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which we operate also regulate one or more of the following:

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the location of wells;

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the method of drilling and casing wells;

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the surface use and restoration of properties upon which wells are drilled; and

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the plugging and abandoning of wells.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

In addition, 11 states have enacted surface damage statutes (“SDAs”). These laws are designed to compensate for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain bonding requirements and specific expenses for exploration and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

We do not control the availability of transportation and processing facilities used in the marketing of our production. For example, we may have to shut–in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.

If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non–discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management, the BOEM (“Bureau of Ocean Energy Management”), the BSEE (“Bureau of Safety and Environmental Enforcement”) or other appropriate federal or state agencies.

Transportation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. The FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index ceiling slightly, effective July 2001. Following the FERC’s five-year review of the indexing methodology, the FERC issued an order in 2006 increasing the index ceiling.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by the FERC under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or NGPA, and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in the adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, the FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised the FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting.

The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Futures Trading Commission, or the CFTC. See below the discussion of “Other Federal Laws and Regulations Affecting Our Industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to Order No. 704, some of our operations may be required to annually report to FERC on May 1 of each year for the previous calendar year. Order No. 704 requires certain natural gas market participants to report information regarding their reporting of transactions to price index publishers and their blanket sales certificate status, as well as certain information regarding their wholesale, physical natural gas transactions for the previous calendar year depending on the volume of natural gas transacted. See below the discussion of “Other Federal Laws and Regulations Affecting Our Industry — FERC Market Transparency Rules.”

Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Although the FERC has set forth a general test for determining whether facilities perform a nonjurisdictional gathering function or a jurisdictional transmission function, the FERC’s determinations as to the classification of facilities is done on a case by case basis. To the extent that the FERC issues an order which reclassifies transmission facilities as gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

State Natural Gas Regulation

Various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

Other Federal Laws and Regulations Affecting Our Industry

Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005, or the EPAct 2005. EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC

with additional civil penalty authority. EPAct 2005 provides the FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increases the FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rule makes it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act, practice, or course of business that operates as a fraud or deceit upon any person. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines.

FERC Market Transparency Rules. On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. The report for calendar year 2010 and subsequent years is May 1 of the following calendar year. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

Item 1A. Risk Factors

You should carefully consider each of the risks described below, together with all of the other information contained in this annual report, including our consolidated financial statements and related notes, included elsewhere in this annual report. The risks described below are not the only risks facing us or that may materially adversely affect our business. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may also materially and adversely affect our business. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected and you may lose all or part of your investment.

You should refer to the explanation of the qualifications and limitations on forward-looking statements included in this annual report under “Cautionary Statements Regarding Forward Looking Statements.” All forward looking statements made by us are qualified by the risk factors described below.

Oil and natural gas prices are volatile, and a substantial or extended decline in oil and natural gas prices could affect our financial results and impede growth.

Our future revenues, profitability and cash flow will depend substantially upon the prices and demand for oil and natural gas. The markets for these commodities are volatile and even relatively modest drops in prices can affect our financial results and impede our growth. Prices for oil and natural gas fluctuate widely in response to relatively

minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:

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domestic and foreign supplies of oil and natural gas;

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price and quantity of foreign imports of oil and natural gas;

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the cost of exploring for, developing, producing, transporting and marketing oil and natural gas;

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actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;

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level of consumer product demand;

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level of global oil and natural gas exploration and productivity;

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domestic and foreign governmental regulations;

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level of global oil and natural gas inventories;

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political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America, Africa, Australia and Russia;

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weather conditions;

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technological advances affecting oil and natural gas consumption;

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volatile trading patterns in the commodity-futures markets;

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overall United States and global economic conditions; and

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price and availability of alternative fuels.

Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower oil and natural gas prices may not only decrease our expected future revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in us having to make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations.

We periodically enter into derivative transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in demand for oil or natural gas would have a material adverse effect on our financial condition and results of operations. Any substantial or extended decrease in crude oil and natural gas prices would render uneconomic a significant portion of our exploration, development and exploitation projects. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in crude oil or natural gas prices or demand for crude or natural gas may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

More stringent regulatory initiatives relating to offshore exploration and production activities may have an adverse effect on our results of operations, financial position and liquidity.

In response to an April 2010 fire and explosion aboard the Deepwater Horizon drilling rig and resulting oil spill from the Macondo well operated by a third party in ultra-deepwater in the Gulf of Mexico, federal authorities have pursued a series of regulatory initiatives to address the direct impact of that incident and to prevent similar incidents in the future. Beginning in 2010 and continuing through 2013, the federal government, acting through the U.S. Department of the Interior (“DOI”) and its implementing agencies, BOEM and BSEE, has issued various rules,

Notices to Lessees and Operators (“NTLs”) and temporary drilling moratoria that impose or result in added environmental and safety measures upon exploration, development and production operators in the Gulf of Mexico. These new regulatory requirements include the following:

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The Environmental NTL, which imposes more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements;

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The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes and also requires certifications of compliance from senior corporate officers;

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The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams; and

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The Workplace Safety Rule, which requires operators to employ a comprehensive safety and environmental management system (“SEMS”) to reduce human and organizational errors as root causes of work-related accidents and offshore spills, which rule was subsequently amended as published on April 5, 2013 (sometimes referred to as the “SEMS II” rule) to require operators to, among other things, establish procedures providing all personnel with “stop work” authority, develop protocols as to whom at the facility has the ultimate operational safety and decision-making authority, and establish an independent auditing regimen whereby facility audits are conducted by a service provider accredited by BSEE that is unaffiliated with the operator.

These regulatory initiatives may serve to effectively slow down the pace of drilling and production operations in the Gulf of Mexico due to adjustments in operating procedures and certification practices as well as increased lead times to obtain exploration and production plan reviews, develop drilling applications, and apply for and receive new well permits. These new requirements also increase the cost of preparing permit applications and will increase the cost of each new well, particularly for wells drilled in deeper waters on the Outer Continental Shelf. We could become subject to fines, penalties or orders requiring us to modify or suspend our operations in the Gulf of Mexico if we fail to comply with these requirements. Moreover, if similar oil spill incidents were to occur in the future in the Gulf of Mexico or elsewhere where we conduct operations, the United States or other countries could elect to again issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental regulatory initiatives regarding offshore oil and gas exploration and development activities, which any one or more of such events could have a material adverse effect on our volume of business as well as our financial position, results of operations and liquidity.

Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations include the U.S. Gulf of Mexico.

We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas production operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the U.S. Gulf of Mexico is especially difficult because most of the removal obligations are many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving and may result in additional or increased costs. As a result, we may make significant increases or decreases to our estimated asset retirement obligations in future periods. For example, because we operate in the U.S. Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimate of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane.

Moreover, the timing for pursuing restoration and removal activities has accelerated for operators in the U.S. Gulf of Mexico following the DOI’s issuance an NTL, effective October 15, 2010, that established a more stringent regimen for the timely decommissioning of what is known as “idle iron” wells, platforms and pipelines that are no longer producing or serving exploration or support functions related to an operator’s lease in the U.S. Gulf of Mexico. Historically, many oil and natural gas producers in the U.S. Gulf of Mexico have delayed the plugging, abandoning or removal of such idle iron until they met the final decommissioning regulatory requirement, which has been established as being within one year after the lease expires or terminates, a time period that sometimes is years after use of the idle iron has been discontinued. The recently issued NTL sets forth new standards that trigger decommissioning timing requirements; any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years’ time. Plugging or abandonment of wells may be delayed by two years if all of such well’s hydrocarbon and sulfur zones are appropriately isolated. Similarly, platforms or other facilities that are no longer useful for operations must be removed within five years of the cessation of operations. The triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts may serve to increase, perhaps materially, our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs. Moreover, the implementation of this NTL could likely result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal costs and increases in an operator’s related asset retirement obligations.

Reserve estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in the reserve estimates or underlying assumptions of our properties will materially affect the quantities and present value of those reserves.

Estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing such estimates, projection of production rates, timing of development expenditures and available geological, geophysical, production and engineering data are analyzed. The extent, quality and reliability of this data can vary. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds, as well as certain regulatory assumptions. If our interpretations or assumptions used in arriving at our reserve estimates prove to be inaccurate, the amount of oil and natural gas that will ultimately be recovered may differ materially from the estimated quantities and net present value of reserves owned by us. Any inaccuracies in these interpretations or assumptions could also materially affect the estimated quantities of reserves shown in the reserve reports.

For example, during September 2013, the Company determined that it could not meet the financial certifications required to obtain permits to develop its offshore EB 920 Project in the Gulf of Mexico, due in large part to the substantially increased Worst Case Discharge assumptions imposed by the BOEM. As a result, the proved undeveloped reserves associated with the EB 920 Project no longer met the requirements of reasonable certainty to remain booked as proved reserves at the end of the third quarter of 2013 and we made downward revisions to eliminate Flatts’ Guitar proved undeveloped reserve. Proved undeveloped reserves related to Flatts Guitar were estimated at 8.4 million barrels of oil equivalent at December 31, 2012, or 71.2% of our total proved undeveloped reserves and 33.3% of our total proved reserves at such date. These proved reserves had an estimated present value discounted at 10% using SEC reserves criteria and pricing (“PV-10”) of approximately $210.1 million at December 31, 2012.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from estimates. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

Approximately 24.7% of our total estimated proved reserves at December 31, 2013 were classified as proved undeveloped and may ultimately prove to be less than estimated.

Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. At December 31, 2013, approximately 24.7% of our total estimated proved reserves were undeveloped. The future development of these undeveloped reserves into proved developed reserves is highly dependent upon our

ability to fund estimated total capital development costs as shown in our reserve report of approximately $29.7 million, of which $21.7 million, zero and zero are expected to be incurred in 2014, 2015 and 2016, respectively. We cannot be sure that these estimated costs are accurate. Further, our drilling efforts may be delayed or unsuccessful, and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and results of operations. For example, we had downward revisions in proved reserves of 2.0 MMBoe based on management’s decision during the fourth quarter of 2013 not to drill certain proved undeveloped reserves in the Oklahoma area that had previously been booked. For a more detailed discussion of our current liquidity, please see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” of this annual report.

Our business may suffer if we lose key personnel.

We depend to a large extent on the services of certain key management personnel, including Howard A. Settle, our President, Chief Executive Officer, and Chairman of the Board of Directors, Jonathan B. Rudney, Co-Founder and a member of our Board of Directors, Jeff T. Craycraft, our Treasurer and Chief Financial Officer, and Elizabeth A. Barr, our Vice President of Administration. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production and developing and executing financing and derivative strategies. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any of our employees. Our success is dependent on our ability to continue to employ and retain skilled technical personnel. Competition for such professionals is intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

Lower oil and natural gas prices may cause us to record ceiling test write-downs.

We use the full-cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties each after income tax effects. If at the end of any quarterly period we determine that the net capitalized costs of oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write down.” This charge does not impact cash flow from operating activities, but does reduce our shareholders’ equity. The risk that we will be required to write down the carrying value of oil and natural gas properties increases when oil and natural gas prices are low or volatile. In addition, write downs may occur if we experience substantial downward adjustments to our estimated proved reserves.

Our derivative activities could result in financial losses or could reduce our net income.

To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil and natural gas, we have and may continue to enter into derivative transactions for a significant portion of our oil and natural gas production. If we experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our derivative obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Our ability to use derivative transactions to protect us from future oil and natural gas price declines will be dependent upon oil and natural gas prices at the time we enter into future derivative transactions and our future levels of derivatives, and as a result our future net cash flows may be more sensitive to commodity price changes.

Our policy has been to utilize derivative transactions to reduce the variability in cash flows associated with a significant portion of our near–term estimated oil and natural gas production. However, our price derivative strategy and future derivative transactions will be determined at our discretion. We are not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current oil and natural gas prices. Accordingly, our price derivative strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Conversely, our derivative strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger

percentage of our future production will not be hedged as compared with the prior few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price changes. Please see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Oil and Gas Derivatives” of this annual report for additional information on our oil and natural gas derivative contracts.

Our derivative transactions expose us to counterparty credit risk.

Our derivative transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

During periods of falling commodity prices, our derivative receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

On July 21, 2010 new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the Commodity Futures Trading Commission (“CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing its ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore the impact of those provisions to us is uncertain at this time.

The Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The full impact of the Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts or increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Act and regulations implementing the Act, our results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

Finally, the Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. Our revenues could therefore be adversely affected if a consequence of the Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial condition and results of operations.

Unless we replace crude oil and natural gas reserves our future reserves and production will decline.

Our future crude oil and natural gas production will depend on our success in finding, developing or acquiring additional reserves. If we are unable to replace reserves through drilling or acquisitions, our level of production and cash flows will be adversely affected. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We also may not be successful in raising funds to acquire additional reserves.

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

The crude oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, production, exploitation and acquisition of crude oil and natural gas reserves. Improvement in commodity prices may result in an increase in our actual capital expenditures. Conversely, a significant decline in product prices could result in a decrease in our capital expenditures. We intend to finance our future capital expenditures primarily through cash flows from operations and through borrowings under our Amended Revolving Credit Facility, however, our financing needs may require us to alter or increase our capitalization substantially. The issuance of additional debt may require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our cash flows from operations and access to capital are subject to a number of variables, including:

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our proved reserves;

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

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

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our ability to acquire, locate and produce new reserves; and

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the ability of our banks to lend.

If our revenues or the borrowing base under our Amended Revolving Credit Facility decrease as a result of lower crude oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing. If cash generated by operations or cash available under our Amended Revolving Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our crude oil and natural gas reserves, and could adversely affect our business, financial condition and results of operations.

Competition for oil and natural gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel resources that could give them an advantage in evaluating and obtaining properties and prospects.

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors are major or independent oil and natural gas companies that possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than us. We actively compete with other companies when acquiring new leases or oil and natural gas properties. For example, new offshore leases may be acquired through a “sealed bid” process and are generally awarded to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and natural gas properties and exploratory prospects than we are able or willing to pay. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.

We may not be able to keep pace with technological developments in our industry.

The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other natural gas and oil companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, and results of operations could be materially adversely affected.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute exploration and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.

We utilize third-party services to maximize the efficiency of our organization. The cost of oil field services typically fluctuates based on demand for those services. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploitation and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.

Drilling for natural gas and oil is a speculative activity involving many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

We engage in exploration and development drilling activities. Any such activities may be unsuccessful for many reasons. In addition to a failure to find oil or natural gas, drilling efforts can be affected by adverse weather conditions (such as hurricanes and tropical storms in the Gulf of Mexico), cost overruns, equipment shortages and mechanical difficulties. Therefore, the successful drilling of a gas or oil well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, could cause a well to become uneconomic or only marginally economic. In addition to their costs, unsuccessful wells could impede our efforts to replace reserves.

Our business involves a variety of inherent operating risks, including:

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fires;

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delays imposed by or resulting from compliance with regulatory requirements;

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pressure or irregularities in geological formations;

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title problems;

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explosions;

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blow-outs and surface cratering;

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uncontrollable flows of crude oil, natural gas, formation water or well fluids;

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natural disasters, such as hurricanes and other adverse weather conditions;

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pipe, cement, subsea well or pipeline failures;

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casing collapses;

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mechanical difficulties, such as lost or stuck oil field drilling and service tools;

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abnormally pressured formations;

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shortages of, or delays in, obtaining drilling rigs or equipment, or water for hydraulic fracturing activities; and

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environmental hazards, such as natural gas leaks, crude oil spills, pipeline or tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well fluids, toxic gases or other pollutants into the surface and subsurface environment.

If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses due to costs and/or liability incurred as a result of:

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injury or loss of life;

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severe damage to and destruction of property, natural resources and equipment;

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pollution and other environmental damage;

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clean-up responsibilities;

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regulatory investigations and penalties;

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suspension of our operations; and

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repairs to resume operations.

Prospects that we decide to drill may not yield crude oil or natural gas in commercially viable quantities.

Prospects that we decide to drill that do not yield crude oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield crude oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether crude oil or natural gas will be present or, if present, whether crude oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

Market conditions or transportation impediments may hinder access to oil and natural gas markets or delay production.

Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines or trucking and terminal facilities. In offshore operations, the availability of a ready market depends on the proximity of and our ability to tie into existing production platforms that we own or operate or that are owned and operated by others and, where facilities are owned and operated by others, the ability to negotiate commercially satisfactory arrangements with the owners or operators. We may be required to shut-in wells or delay initial production for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we will be unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.

We are not the operator on all of our current properties and we will not be the operator on all of our future properties and therefore will not be in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves on certain of such properties.

We currently operate 100% of our wells (excluding Oklahoma); however, as we carry out our planned drilling program, we will not serve as operator of all planned wells. We conduct and intend to conduct many of our operations through joint ventures in which we share control with other parties. We are not the well operator for several of our joint ventures. There is the risk that our partners may at any time have economic, business or legal interests or goals that are inconsistent with those of the project or us. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

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the timing and amount of capital expenditures;

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the availability of suitable drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;

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the operator’s expertise and financial resources;

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approval of other participants in drilling wells;

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selection of technology; and

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the rate of production of the reserves.

Our insurance may not protect us against all business and operating risks.

We do not maintain insurance for all of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance policies are economically unavailable or available only for reduced amounts of coverage. Therefore, we will not be fully insured against all risks, including high-cost business interruption insurance and drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations. As a result of a number of recent catastrophic events like the terrorist attacks on September 11, 2001 and Hurricanes Katrina, Rita, Gustav and Ike, as well as the recent Deepwater Horizon disaster, insurance underwriters increased insurance premiums for many of the coverages historically maintained and issued general notices of cancellation and significant changes for a wide variety of insurance coverages. The oil and natural gas industry suffered extensive damage from Hurricanes Katrina, Rita, Gustav and Ike. As a result, insurance costs have increased significantly from the costs that similarly situated

participants in this industry have historically incurred. Insurers are requiring higher retention levels and limit the amount of insurance proceeds that are available after a major wind storm in the event that damages are incurred. If storm activity in the future is as severe as it was in 2005, or if there is another catastrophic event similar to the Deepwater Horizon incident, insurance underwriters may no longer insure Gulf of Mexico assets against weather-related damage. Our business interruption insurance may not be economically available in the future, which could adversely impact business prospects in the Gulf of Mexico and adversely impact our operations. If an accident or other event resulting in damage to our operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a customer, it could adversely affect our financial condition and results of operations. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.

Our operations are subject to complex government laws and regulations that may expose us to significant costs and liabilities.

Crude oil and natural gas exploration and production operations in the United States and the U.S. Gulf of Mexico are subject to extensive federal, regional, state and local laws and regulations. Companies operating onshore and in the U.S. Gulf of Mexico are subject to laws and regulations addressing, among other items, land use and lease permit restrictions, bonding and other financial assurance related to drilling and production activities, spacing of wells, unitization and pooling of properties, plugging and abandonment of wells and associated infrastructure after production has ceased and operational reporting and taxation. We may be required to make significant capital and operating expenditures or perform other corrective actions at our wells and properties to comply with the requirements of these laws and regulations or the terms or conditions of permits issued pursuant to such requirements, and our compliance with future laws or regulations, or with any adverse change in the interpretation or enforcement of existing laws and regulations, could increase such compliance costs. Regulatory limitations and restrictions could also delay or curtail our operations and could have a significant impact on our financial condition or results of operations.

We may incur significant costs and liabilities in complying with environmental laws and regulations.

Our oil and natural gas exploration, development and production operations are subject to stringent federal, regional, state and local laws and regulations governing the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:

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require the acquisition of a permit before conducting drilling or other regulated activity commences;

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restrict the types, quantities and concentration of materials that can be released into the environment in connection with regulated activities;

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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

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impose substantial liabilities for pollution resulting from operations; and

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require decommissioning or plugging of abandoned platforms and wells.

Numerous governmental authorities, such as the EPA and analogous state environmental agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Failure to comply with these laws and regulations or the terms or conditions of required environmental permits may result in the assessment of sanctions, including administrative, civil and/or criminal penalties; the imposition of investigatory, remedial or corrective action obligations; and the issuance of injunctions or orders limiting or prohibiting some or all of our operations.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbon and wastes, because of air emissions and wastewater discharges related to our operations, and as a result of historical operations and waste disposal practices. For example, in response to recent seismic events near underground injection wells used for the disposal of oil and gas-

related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells; if new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position. Under certain environmental laws and regulations that impose strict, joint and several liability, we may be required to remediate contamination on our properties regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws and regulations at the time those actions were taken. Claims for damages to persons, property or natural resources may result from environmental and other impacts of our operations. In addition, future spills or releases of regulated substances or accidents or the discovery of currently unknown contamination could expose us to material losses, expenditures and environmental or health and safety liabilities, including liabilities resulting from lawsuits brought by private litigants or neighboring property owners or operators for personal injury or property damage related to our operations or the land on which our operations are conducted.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well construction, drilling, water management, or completion activities, or waste handling, storage, transport, disposal or cleanup requirements or other unforeseen liabilities could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance. See Item 1, “Business—Environmental Matters and Regulation” of this annual report.

We may experience difficulty in achieving and managing future growth.

Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:

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our ability to obtain leases or options on properties for which we have 3-D seismic data;

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our ability to acquire additional 3-D seismic data;

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our ability to identify and acquire new exploratory prospects;

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our ability to develop existing prospects;

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our ability to continue to retain and attract skilled personnel;

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our ability to maintain or enter into new relationships with project partners and independent contractors;

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the results of our drilling program;

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hydrocarbon prices; and

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our access to capital.

We may not be successful in upgrading our technical, operations, and administrative resources or in increasing our ability to internally provide certain of the services currently provided by outside sources, and we may not be able to maintain or enter into new relationships with project partners and independent contractors. Our inability to achieve or manage growth may adversely affect our financial condition and results of operations.

Climate change legislation and regulatory initiatives restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.

according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations to restrict emissions of greenhouse gases under existing provisions of the CAA that, among other things, establish PSD provisions and Title V operating permit reviews of certain large stationary sources that are potential major sources of greenhouse gas emissions. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified sources in the United States, including, among others, onshore and offshore oil and natural gas production facilities, on an annual basis, which includes certain of our oil and natural gas operations.

While the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing greenhouse gas emissions by means of cap and trade programs that typically require major sources of greenhouse gas emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those greenhouse gases. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact the Company’s business, any such future laws and regulations that require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

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

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We conduct hydraulic fracturing in our operations. The process is typically regulated by state oil and gas commissions or other similar state agencies but the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel fuels and issued revised permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency continues to project issuance of a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. In addition, Congress from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states, including Louisiana, Texas, Oklahoma and California, where we conduct operations, have adopted or are considering adopting legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells. For example, concerns related to hydraulic fracturing activities in California have led to the state legislature proposing bans and other measures restricting hydraulic

fracturing, and operators are reportedly experiencing delays in obtaining permits to drill new wells while the state oil and gas agency promulgates new regulations related to hydraulic fracturing fluid chemical additive disclosure, water management and groundwater protection.

In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing activities, with a draft final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review in 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards in 2014. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods and issued a report in 2011 on immediate and longer-term actions that may be taken to reduce environmental and safety risks of shale gas development. Also, in May 2013, the federal Bureau of Land Management published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used in hydraulic fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or under newly established legislation.

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:

•

actual prices we receive for crude oil and natural gas;

•

actual cost of development and production expenditures;

•

the amount and timing of actual production; and

•

changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

An increase in interest rates would increase the cost of servicing our indebtedness and could reduce our profitability.

Indebtedness we may incur under the Amended Revolving Credit Facility will bear interest at variable rates. As a result, an increase in interest rates, whether because of an increase in market interest rates or an increase in our own cost of borrowing, would increase the cost of servicing our indebtedness and could materially reduce the availability of debt financing, which may result in increases in the interest rates and borrowing spreads at which lenders are willing to make future debt financing available to us. The impact of such an increase would be more significant than it would be for some other companies because of our substantial indebtedness.

We plan to pursue acquisitions as part of our growth strategy and there are risks in connection with acquisitions.

Our growth has been attributable in part to acquisitions of producing properties and companies. We expect to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms we consider favorable. However, we cannot assure you that suitable acquisition candidates will be identified in the future, or that we will be

able to finance such acquisitions on favorable terms. In addition, we compete against other companies for acquisitions, and we cannot assure you that we will successfully acquire any material property interests. Further, we cannot assure you that future acquisitions by us will be integrated successfully into our operations or will increase our profits.

The successful acquisition of producing properties requires an assessment of numerous factors beyond our control, including, without limitation:

•

recoverable reserves;

•

exploration potential;

•

future oil and natural gas prices;

•

operating costs; and

•

potential environmental and other liabilities.

In connection with such an assessment, we perform a review of the subject properties. The resulting assessments are inexact and their accuracy uncertain, and such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is made. Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geologic characteristics or geographic location than our existing properties. While our current operations are focused in the federal and state waters of the Gulf of Mexico, offshore Louisiana and onshore Louisiana, Texas, and California, we may pursue acquisitions or properties located in other geographic areas.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

President Obama’s proposed Fiscal Year 2014 Budget includes proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination or postponement of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs and (iii) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred by independent producers in connection with the exploration for, or development of, oil or natural gas within the United States. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals, tax reform efforts, or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available to us with respect to our oil and natural gas exploration and development activities, and any such change could have an adverse effect on our financial condition and results of operations.

The covenants in the indenture governing our 12.5% Senior Notes due 2015 (the “Senior Notes”) and our Amended Revolving Credit Facility could negatively impact our financial condition, results of operations and business prospects and prevent us from fulfilling our obligations under the notes.

The covenants contained in the indenture governing the Senior Notes and our Amended Revolving Credit Facility could have important consequences for our operations, including:

•

making it more difficult for us to satisfy our obligations under the Senior Notes or other indebtedness and increasing the risk that we may default on our debt obligations;

•

requiring us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;

•

limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities;

•

limiting management’s discretion in operating our business;

•

limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•

limiting our ability to hedge our production;

•

detracting from our ability to successfully withstand a downturn in our business or the economy generally;

•

placing us at a competitive disadvantage against less leveraged competitors; and

•

making us vulnerable to increases in interest rates, because debt under our Amended Revolving Credit Facility may vary with prevailing interest rates.

We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the indenture governing the Senior Notes and our Amended Revolving Credit Facility, it could lead to an event of default and the consequent acceleration of our obligation to repay outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions. Please see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Amended Revolving Credit Facility” and “—12.50% Senior Secured Notes due 2015” of this annual report for additional information on our covenants and other restrictions.

While we believe we have taken the steps necessary to remediate a previously identified deficiency in our internal control over financial reporting, if one or mare material weaknesses recur or if we fail to maintain effective internal control over financial reporting in the future, our ability to report our financial results on a timely and accurate basis may be adversely affected.

During 2013, our management identified material weaknesses in our internal control over financial reporting during the year ended December 31, 2012. As a result of these material weaknesses, our principal executive officer and principal financial officer concluded that, as of December 31, 2012, we did not maintain effective disclosure controls and procedures or internal control over financial reporting. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis by employees in the normal course of their work.

Although we believe we have taken the steps necessary to remediate theses material weaknesses and improve the effectiveness of our disclosure controls and procedures and internal control over financial reporting, we can give no assurances that the measures we take will prevent the recurrence of these or similar weaknesses that we may identify, or that any additional material weaknesses will not arise, in the future. We will continue to monitor the effectiveness of these and other processes, procedures and controls and will make any further changes management determines appropriate.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 2. Properties

We own a 19,673 square foot building in The Woodlands, Texas. We lease 7,735 square feet of office space in Lexington, Kentucky from one of our affiliates that expires on December 31, 2015. For more information, see Item 13, “Certain Relationships and Related Party Transactions.” In addition, we also lease (i) 14,456 square feet of office space in New Orleans, Louisiana, which expires on May 31, 2016; (ii) 2,388 square feet of office space in Lakewood, Colorado, which expires on November 30, 2016; and (iii) 3,103 square feet of office space in Bakersfield, California, which expires on May 31, 2014.

For more information regarding our oil and natural gas properties, please read Item 1, “Business.”

Item 3. Legal Proceedings

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

The Company and three other operators in the Breton Sound Area are required to design and conduct a produced water study pursuant to a compliance order issued by the Louisiana Department of Environmental Quality (LDEQ) prohibiting the commercial discharge of produced water from facilities in coastal waters of Louisiana. The group has hired the appropriate consultants to assist with the study design. The group is currently waiting on the LDEQ to issue a revised Compliance Order, outlining the revised compliance schedule based on the agreed upon modifications. Once the program format has been approved by the LDEQ, we will implement the program by collecting samples of produced water ready for discharge and recording the analytical results of testing performed. The Company is awaiting a revised compliance order and new compliance schedule from LDEQ, so that the necessary sampling and analyses may be performed and the results evaluated to determine whether a waiver may be issued by the LDEQ that would allow similar type discharges from these coastal facilities on a going forward basis or if other, potentially more costly, remedial measures, such as the injection of generated produced water into offshore disposal wells, may be warranted.

As previously disclosed, on January 25, 2011, the Company filed suit against the United States Government in United States Court of Federal Claims in Washington D.C. claiming a breach of contract on the lease governing the EB 920 Project, an offshore lease located in the deep waters of the Gulf of Mexico. In March 2013, the United States Court of Federal Claims granted the U.S. Government’s motion for summary judgment on those claims. On September 5, 2013, the Company filed an appeal to the summary judgment in United States Federal Circuit Court of Appeal in Washington D.C., reasserting our claim of a breach of contract by the U.S. Government with respect to the EB 920 Project. There are a number of issues relative to the Government’s breach of the Company’s lease. A major claim of breach is that due to the post-lease change in the rules of calculation of the WCD under Notice to Lessees 2010-06 (“NTL06”), the Company can no longer receive a permit to drill EB 920. The Company cannot develop the lease or receive the benefit of the proved reserves which exist on the lease and for which the Company paid the Government $23.2 million. The new post-lease rules of calculation for WCD did not exist prior to the issuance of NTL06. The Company argues that the post-lease changes to the method of the calculation are substantive both in terms of volumes and financial responsibility. The Government argues they are not substantive. A panel of judges heard the appeal in early January 2014. In March 2014, our appeal was denied. The Company is currently evaluating its options in this case.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is not traded on a United States established public trading market. As of March 28, 2014, there were 203 holders of record of our common stock. During 2013, dividends were paid at $25.00 per share to shareholders of record of our common stock effective March 15, 2013. During 2012, dividends were paid at $25.00 per share to shareholders of record effective March 15, 2012, June 25, 2012, September 24, 2012 and December 17, 2012. During 2011, dividends were paid at $25.00 per share to shareholders of record of our common stock effective March 1, 2011, June 15, 2011, September 15, 2011 and December 1, 2011. The Board of Directors, in its discretion, will continue to make decisions regarding the payment of dividends on a quarterly basis. In addition, the indenture, dated September 24, 2010, we entered into in connection with the issuance of our 12.50% senior secured notes due 2015 (the “2015 Senior Secured Notes Indenture”), limits our ability to pay dividends.

Item 6. Selected Financial Data

The following table presents our summary consolidated historical financial data for the periods and as of the dates indicated. The statement of operations and balance sheet data for the five years ended December 31, 2013, 2012, 2011, 2010 and 2009 are derived from our consolidated financial statements. For further information that will help you better understand the summary data, you should read this financial data in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes and other financial information included elsewhere in this annual report. These historical results are not necessarily indicative of results to be expected for any future periods.


	2013			2012			2011			2010			2009
In thousands													Unaudited
Statement of Operations Data:
Revenues
Gas sales	$	62,953		$	63,535		$	87,064		$	79,331		$	75,312
Oil sales		91,618			119,504			113,722			83,122			65,709
Realized and unrealized gains (losses) on derivatives, net		(5,038	)		20,769			13,650			17,417			44,420
Insurance proceeds		—			—			—			—			20,207

Total revenues		149,533			203,808			214,436			179,870			205,648
Costs and expenses:
Production and delivery costs		35,003			35,529			34,326			31,569			25,831
Production taxes		7,965			9,314			10,259			5,732			5,894
Workover costs		3,729			2,772			7,730			10,470			8,439
Depreciation, depletion and amortization		426,061			118,041			71,763			67,312			66,285
General and administrative expenses		21,359			20,780			28,861			16,731			20,573

Total operating expenses		494,117			186,436			152,939			131,814			127,022

Income (loss) from operations		(344,584	)		17,372			61,497			48,056			78,626
Other income (expenses):
Interest income		117			78			244			276			363
Interest expense		(29,686	)		(21,315	)		(17,198	)		(9,057	)		(4,349	)
Income (loss) on equity investment		—			—			(2,044	)		(5,156	)		492
Loss on sale or disposal of inventory		—			(954	)		(20	)		(1,463	)		(1,257	)
Other income (expense), net		(126	)		431			204			434			861

Total other income (expenses)		(29,695	)		(21,760	)		(18,814	)		(14,966	)		(3,890	)

Income (loss) before taxes		(374,279	)		(4,388	)		42,683			33,090			74,736
Income tax provision (benefit)		(134,080	)		(1,796	)		17,295			5,794			33,580

Net income (loss) including noncontrolling interest		(240,199	)		(2,592	)		25,388			27,296			41,156
Net income attributable to noncontrolling interest		1,218			1,314			1,524			1,682			715

Net income (loss) attributable to RAAM Global	$	(241,417	)	$	(3,906	)	$	23,864		$	25,614		$	40,441

Statement of Cash Flows Data:
Capital expenditures	$	126,320		$	180,500		$	228,178		$	86,936		$	137,794
Cash flow provided by (used in):
Operating activities		78,742			128,278			172,928			114,209			185,505
Investing activities		(52,652	)		(155,007	)		(246,034	)		(87,838	)		(142,334	)
Financing activities		(3,903	)		43,657			43,817			25,773			(22,335	)
Balance Sheet Data (at period end):
Cash and cash equivalents	$	90,858		$	68,671		$	51,743		$	81,032		$	28,888
Oil and gas properties, net		287,118			654,268			615,907			461,363			452,683
Total assets		426,612			779,454			744,552			621,698			575,618
Total debt, including current portion		256,111			254,541			204,634			152,653			114,122
Total shareholders’ equity		50,015			293,549			302,391			295,201			270,885

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the “Selected Financial Data” and the financial statements and related notes included elsewhere in this annual report. The following discussion and analysis contains forward looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward looking statements. Known material factors that could cause or contribute to such differences include the volatility of oil and natural gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this annual report, particularly in Item 1A, “Risk Factors” and “Cautionary Note Regarding Forward Looking Statements,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward looking events discussed may not occur.

Overview

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

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

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

At December 31, 2013, based on the reserve reports, our estimated total proved oil and natural gas reserves were approximately 10,725 MMBoe, with estimated proved developed reserves of 8,078 MMBoe, or 75.3% of our total estimated proved reserves. Oil comprises approximately 34.5% of our total estimated proved reserves. For the year ended December 31, 2013, daily production averaged 9,210 Boepd.

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

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

Prices for oil and gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and gas activities, commodity prices have experienced significant fluctuations. Our quarterly and annual average net oil and natural gas prices are shown in the tables below.


	2013
	2013			Q1		Q2			Q3			Q4
Oil:
Average price before derivatives ($/Bbl)(1)	$	103.52		$	107.90	$	106.94		$	114.74		$	82.87
Average price differentials(2)	$	11.30		$	18.03	$	14.84		$	7.93		$	4.39
Natural Gas:
Average price before derivatives ($/Mcf)(1)	$	4.24		$	4.03	$	4.55		$	4.04		$	4.38
Average price differentials(2)	$	(0.03	)	$	0.06	$	(0.12	)	$	(0.11	)	$	0.03

	2012
	2012			Q1		Q2			Q3			Q4
Oil:
Average price before derivatives ($/Bbl)(1)	$	108.28		$	110.11	$	110.41		$	107.46		$	105.55
Average price differentials(2)	$	13.08		$	12.62	$	12.27		$	14.19		$	13.25
Natural Gas:
Average price before derivatives ($/Mcf)(1)	$	3.45		$	3.48	$	3.02		$	3.36		$	3.90
Average price differentials(2)	$	0.23		$	0.22	$	0.36		$	0.16		$	0.17

(1)	Oil and natural gas prices do not include the effect of derivative contract settlements.

(2)	Price differential compares oil and natural gas prices, without giving effect to derivative contract settlements, to West Texas Intermediate crude index prices and Henry Hub natural gas prices, respectively.

Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the United States dollar in international currency markets. Factors affecting the price of natural gas include North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas and the availability and accessibility of natural gas deposits in North America.

In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we are a party to derivative contracts and other price protection contracts, and we intend to enter into such transactions in the future to reduce the effect of oil and natural gas price volatility on our cash flows. If the global economic instability continues, commodity prices may be depressed for an extended period of time, which could alter our development plans and adversely affect our growth strategy and our ability to access additional funding in the capital markets.

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

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

Our capitalized oil and gas property costs are subject to a “ceiling test,” which limits such costs to the aggregate of the estimated present value, discounted at 10%, of future net cash flows from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair value of unproved properties, each after income tax effects. There were “ceiling test” write downs of $336.0 million (made up of a $276.9 million write down in the third quarter and a $59.1 million write down in the fourth quarter) and $37.0 million in 2013 and 2012, respectively. There were no write downs resulting from the “ceiling test” in 2011. The significant ceiling test write-down we recorded during the year ended December 31, 2013 is primarily a result of the downward revisions to eliminate the EB 920 Project proved undeveloped reserves. During September 2013, the Company determined that it could not meet the financial certifications required to obtain permits to develop its offshore EB 920 Project in the Gulf of Mexico, due in large part to the substantially increased WCD assumptions imposed by the BOEM. As a result, the proved undeveloped reserves associated with the EB 920 Project no longer met the requirements of reasonable certainty to remain booked as proved reserves at September 30, 2013. Proved undeveloped reserves related to the EB 920 Project were estimated at 8.4 million barrels of oil equivalent at December 31, 2012, or 71.2% of our total proved undeveloped reserves and 33.3% of our total proved reserves at such date. These proved reserves had an estimated present value discounted at 10% using SEC reserves criteria and pricing (“PV-10”) of approximately $210.1 million at December 31, 2012.

Recent Developments

Mid-Continent Sale. During the fourth quarter of 2013, the Company sold approximately 62,000 net acres in oil, gas and/or mineral leases located in Texas and Colorado. The Company also sold approximately 34,000 net acres in oil, gas and/or mineral leases located in Oklahoma. The acres sold in Oklahoma represented 3.6% of the Company’s reserves as of December 31, 2012. The acreage sold in Texas and Colorado did not have proved reserves associated with it. The Company received $51.6 million in cash consideration, which it plans to use for capital expenditures.

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. The following table contains financial and operational data for each of the three years ended December 31, 2013, 2012 and 2011.


	Year Ended December 31,
	2013			2012			2011
Average daily production:
Oil (Bbl per day)		2,425			3,015			2,877
Natural gas (Mcf per day)		40,711			50,304			48,303
Oil equivalents (Boe per day)		9,210			11,399			10,927
Average prices:⁽¹⁾
Oil ($/Bbl)	$	103.52		$	108.28		$	108.30
Natural gas ($/Mcf)	$	4.24		$	3.45		$	4.94
Oil equivalents ($/Boe)	$	45.98		$	43.87		$	50.34
Production expense ($/Boe)	$	10.41		$	8.52		$	8.61
General and administrative expense ($/Boe)	$	6.35		$	4.98		$	7.03
Net income (loss) attributable to RAAM Global (in thousands)	$	(241,417	)	$	(3,906	)	$	23,864
Adjusted EBITDA⁽²⁾ (in thousands)	$	84,730		$	143,731		$	125,305

(1)	Average prices presented do not give effect to our derivative contracts. Please see “— Oil and Gas Derivatives” for a discussion of our derivative activities.

(2)

Adjusted EBITDA as used herein represents net income (loss) before unrealized gains (losses) on derivatives, interest expense, income taxes, and 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 GAAP to Adjusted EBITDA for the periods indicated.


	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Net income (loss) attributable to RAAM Global	$	(241,417	)	$	(3,906	)	$	23,864
Total (gains) losses on derivatives, net, less cash received in settlement of commodity derivatives		4,480			10,077			(4,815	)
Interest expense		29,686			21,315			17,198
Depreciation, depletion and amortization		426,061			118,041			71,763
Income taxes		(134,080	)		(1,796	)		17,295

Adjusted EBITDA	$	84,730		$	143,731		$	125,305

Set forth below is an explanation of certain of the expenses and other financial items that we disclose in our financial statements. We utilize the full-cost method of accounting for our oil and natural gas properties.

Production and delivery costs. Production and delivery costs consists of costs incurred to manage our production facilities and development operations, overhead, well control expenses and repairs and maintenance charges.

Production taxes. Production taxes are severance taxes levied by state governments on oil and gas production based on the value and/or quantity of production. The taxes are calculated using varying specified rates for certain geographic areas in which the Company’s producing wells are located.

Workover costs. Workover costs consist of costs incurred to perform procedures on wells that need certain mechanical changes or enhancements to maintain or increase production.

Depreciation, depletion and amortization. All capitalized costs of oil and gas properties are amortized through depreciation, depletion and amortization (“DD&A”) using the future gross revenue method whereby the annual provision is computed by dividing revenue earned during the period by future gross revenues at the beginning of the period, and applying the resulting rate to the cost of oil and gas properties, including estimated future development and abandonment costs. Investments in unproved properties and major development projects are not amortized until proved reserves are attributed to the projects or until impairment occurs. If the results of an assessment indicate that the properties are impaired, that portion of such costs is added to the capitalized costs to be amortized. Capitalized oil and gas property costs are subject to a “ceiling test,” which limits such costs to the aggregate of the estimated present value, discounted at 10%, of future net cash flows from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair value of unproved properties, each after income tax effects. If a write down occurs, it is recorded within this category of the statement of operations for the period.

General and administrative expenses. General and administrative expenses include payroll and benefits for our corporate staff, costs of maintaining our headquarters, certain data processing charges, property taxes, audit and other professional fees and legal compliance.

Interest expense. Interest expense reflects interest incurred on our outstanding debt instruments.

Income tax provision. The asset and liability method prescribed by the Financial Accounting Standards Board’s guidance requires recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the tax bases and financial reporting bases of assets and liabilities. Our income tax provision consists of both (a) current federal, state, and local income tax expenses and (b) deferred federal, state, and local income tax expenses.

Results of Operations

The following table sets forth the results of operations for the years ended December 31, 2013, 2012 and 2011. Because of normal production declines, increased or decreased drilling activity and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as indicative of future results.


	Year Ended December 31,
	2013			2012			2011
	(dollars in thousands)
Revenues:
Gas sales	$	62,953		$	63,535		$	87,064
Oil sales		91,618			119,504			113,722
Realized and unrealized gains (losses) on derivatives, net		(5,038	)		20,769			13,650

Total revenues		149,533			203,808			214,436
Costs and expenses:
Production and delivery costs		35,003			35,529			34,326
Production taxes		7,965			9,314			10,259
Workover costs		3,729			2,772			7,730
Depreciation, depletion and amortization		426,061			118,041			71,763
General and administrative expenses		21,359			20,780			28,861

Total operating expense		494,117			186,436			152,939

Income (loss) from operations		(344,584	)		17,372			61,497
Other income (expenses):
Interest expense, net		(29,569	)		(21,237	)		(16,954	)
Loss from equity investment		—			—			(2,044	)
Loss on sale or disposal of inventory		—			(954	)		(20	)
Other income (expense), net		(126	)		431			204

Total other income (expenses)		(29,695	)		(21,760	)		(18,814	)

Income (loss) before taxes		(374,279	)		(4,388	)		42,683
Income tax provision (benefit)		(134,080	)		(1,796	)		17,295

Net income (loss) including noncontrolling interest		(240,199	)		(2,592	)		25,388
Net income attributable to noncontrolling interest		1,218			1,314			1,524

Net income (loss) attributable to RAAM Global	$	(241,417	)	$	(3,906	)	$	23,864

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Revenues

Oil and natural gas production. Oil and natural gas production for the year ended December 31, 2013 decreased to 3.4 MMBoe from 4.2 MMBoe for the year ended December 31, 2012. Gas and oil production for the year ended December 31, 2013 decreased by 19% and 20%, respectively, over the year ended December 31, 2012. The decrease in production during 2013 was mainly due to casing failures in several wells in the Yegua Trend which went offline late during the second quarter of 2013 and required new wells to be drilled. The casing failures were due to a formation collapse resulting from the normal decrease in formation pressure as the field was produced. As a result of this casing failure, one new well and one side-tracked well were drilled, completed and placed online during September 2013. This decrease in production was offset by the increase in production from seven new wells that the Company brought online during 2013 (mainly in the last half of the year) but the new production from these wells did not keep pace with the declines from the mature wells in the offshore fields.

Total revenues. Total revenues for the year ended December 31, 2013 decreased to $149.5 million from $203.8 million for the year ended December 31, 2013. Gas revenues (exclusive of derivatives) decreased by $0.6 million due to the net effects of lower gas volumes and higher gas prices. Gas prices increased by 23% from an average price of $3.45 for the year ended December 31, 2012 to an average gas price of $4.24 for the year ended December 31, 2013.

Oil revenues (exclusive of derivatives) decreased by $27.9 million due to lower oil volumes and lower oil prices. Oil prices decreased by 4% from an average oil price of $108.28 for the year ended December 31, 2012 to an average oil price of $103.52 for the year ended December 31, 2013.

Realized and unrealized gains (losses) on derivatives, net. Realized and unrealized gains (losses) on derivatives, net, were a loss of $5.0 million for the year ended December 31, 2013 as compared to a gain of $20.8 million for the year ended December 31, 2012. During 2012, the Company monetized gas derivatives and received $23.3 million which mainly accounts for the significant difference between the two years. The remainder of the fluctuation from year to year is due to the volatility of oil and natural gas prices and changes in the fair values of our outstanding derivative contracts during these periods.

During 2013, the Company realized a net increase in average prices from the sale of oil and natural gas of $2.11 per barrel resulting in an average sales price of $45.98 per Boe as of December 31, 2013 compared to an average sales price of $43.87 per Boe as of December 31, 2012. This decline was due to the lower oil prices coupled with higher gas prices.

Operating Costs and Expenses

Production and delivery costs. Our production and delivery costs for 2013 decreased in total to $35.0 million, or $10.41 per Boe, from $35.5 million in 2012, or $8.52 per Boe. The decrease in production and delivery costs was primarily attributable to lower costs for boat transportation, Safety and Environmental Management System (SEMS) compliance efforts and supplies and tools. The rate per Boe increased during 2013 due to lower production volumes.

Production taxes. Production taxes for 2013 decreased to $8.0 million from $9.3 million in 2012. The Company pays production taxes to state governments at rates specified by geographic location and commodity. The decrease in production taxes is mainly a result of the decrease in realized oil revenues between periods and a reduction in the gas severance tax rate.

Workover costs. Our workover costs for 2013 increased to $3.7 million, or $1.11 per Boe, from $2.8 million in 2012, or $0.66 per Boe. Workovers are performed on wells that need certain mechanical changes or enhancements to maintain or increase production. Workover projects performed during 2013 had higher equipment rental, lift boat and transportation costs than those performed during 2012.

Depreciation, depletion and amortization. Depreciation, depletion and amortization for 2013 increased to $426.1 million from $118.0 million in 2012. Depreciation, depletion and amortization for the year ended December 31, 2013 increased to $126.75 per Boe including the effect of the ceiling test write-downs ($26.77 per Boe, excluding the ceiling test write-downs) up from $28.29 per Boe including the effect of the ceiling test write-downs during 2012 ($19.43 per Boe, excluding the ceiling test write-downs) for the year ended December 31, 2012. The increase in depreciation, depletion and amortization was primarily due to “ceiling test” write-downs of $336.0 million during 2013 as compared to write downs of $37.0 million during 2012.

General and administrative expenses. General and administrative expenses increased to $21.4 million in 2013 up from $20.8 million in 2012. The increase in general and administrative expenses was principally due to stock-based compensation awarded to employees for sales of certain non-core assets and higher legal and accounting fees offset by reductions in rent and repairs and maintenance expenses.

Interest expense, net. Net interest expense increased to $29.6 million in 2013 up from $21.2 million in 2012 due to higher debt levels and a higher weighted average interest rate. Debt balances averaged $250.0 million during 2013 and $228.9 million during 2012. Interest rates averaged 11.9% during 2013 and 11.1% during 2012. Amounts of interest expense capitalized to net oil and gas properties during 2013 and 2012 are discussed in Item 8, “Notes to Consolidated Financial Statements—Note 2, Significant Accounting Policies.”

Loss from equity investment. The Company did not have any losses from equity investments during the years ended December 31, 2013 and 2012.

Loss on sale or disposal of inventory. The Company did not have a loss on sale or disposal of inventory for the year ended December 31, 2013. During 2012, the Company recorded a $1.0 million loss because the majority of pipe and casing inventory in storage yards was sold to an unrelated third party after it was determined that it would not be utilized in the Company’s projected 2013 drilling program.

Other income (expense), net. For 2013, other expense was $126,000 as compared to other income of $431,000 in 2012. The decrease was mainly due to the timing of receipt of various non-recurring miscellaneous income items.

Income tax benefit. For 2013, the Company recorded an income tax benefit of $134.1 million as compared to an income tax benefit of $1.8 million for 2012. Income tax benefits recognized were based on effective tax rates of 35.8% for 2013 and 40.9% for 2012. The Company’s effective tax rate differs from the statutory U.S. federal income tax rate primarily because of state and local income taxes and tax percentage depletion in excess of cost basis. The Company’s state and local income tax rate in 2013 decreased from 2012 as a result of having a higher 2013 apportionment of its taxable income in a state with lower statutory tax rates where the Company performed the majority of its income-producing activities.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Revenues

Oil and natural gas production. Oil and natural gas production for the year ended December 31, 2012 increased to 4.2 MMBoe from 4.0 MMBoe for the year ended December 31, 2011. Gas and oil production for the year ended December 31, 2012 increased by 4% and 5%, respectively, over the year ended December 31, 2011. The increase in production during 2012 was due to increased gas and condensate production from onshore Texas and increased oil production from California which more than offset the decline in production mainly from the offshore wells in federal waters.

Total revenues. Total revenues for the year ended December 31, 2012 decreased to $203.8 million from $214.4 million for the year ended December 31, 2011. Gas revenues (exclusive of derivatives) decreased by $23.5 million or 27% due to lower gas prices which declined by 30% from an average price of $4.94 for the year ended December 31, 2011 to an average gas price of $3.45 for the year ended December 31, 2012.

Oil revenues (exclusive of derivatives) increased by $5.8 million or 5% due to an increase in oil volumes of 53,561 barrels or 5%. The average oil price of $108.28 for the year ended December 31, 2012 was approximately the same as the $108.30 price for the year ended December 31, 2011.

Realized and unrealized gains (losses) on derivatives, net. Realized and unrealized gains on derivatives, net were $20.8 million for the year ended December 31, 2012 as compared to $13.6 million for the year ended December 31, 2011. The significant fluctuation between years represents the monetization of gas derivatives during 2012 coupled with the volatility of oil and natural gas prices and changes in the fair values of our outstanding derivative contracts during these periods.

During 2012, the Company realized a net decline in average prices from the sale of oil and natural gas of $6.47 per barrel resulting in an average sales price of $43.87 per Boe as of December 31, 2012 compared to an average sales price of $50.34 per Boe as of December 31, 2011. This decline was mainly due to the lower gas prices.

Operating Costs and Expenses

Production and delivery costs. Our production and delivery costs for 2012 increased to $35.5 million, or $8.52 per Boe, from $34.3 million in 2011, or $8.61 per Boe. The increase in production and delivery costs was primarily attributable to higher costs for contract pumping services and Safety and Environmental Management System (SEMS) compliance efforts offset by lower lift boat and engineering services.

Production taxes. Production taxes for 2012 decreased to $9.3 million from $10.3 million in 2011. The Company pays production taxes to state governments at rates specified by geographic location and commodity. The decrease in production taxes is due to the decrease in realized oil and gas revenues between periods.

Workover costs. Our workover costs for 2012 decreased to $2.8 million, or $0.66 per Boe, from $7.7 million in 2011, or $1.94 per Boe. Workovers are performed on wells that need certain mechanical changes or enhancements to maintain or increase production. Due to mechanical needs as well as new governmental regulations, the Company performed more workovers during 2011 than were necessary during 2012.

Depreciation, depletion and amortization. Depreciation, depletion and amortization for 2012 increased to $118.0 million from $71.8 million in 2011. Depreciation, depletion and amortization for the year ended December 31, 2012 increased to $28.29 per Boe including the effect of the ceiling test write-downs ($19.43 per Boe, excluding the ceiling test write-downs) up from $17.99 per Boe for the year ended December 31, 2011. The increase in depreciation, depletion and amortization was primarily due to a larger net oil and gas property base at December 31, 2012 as compared to December 31, 2011 and “ceiling test” write-downs of $37.0 million during 2012.

General and administrative expenses. General and administrative expenses decreased to $20.8 million in 2012 down from $28.9 million in 2011. The decrease in general and administrative expenses was principally due to lower legal fees, improvements in accounts receivable aging and the related reversal of the allowance, and stock-based compensation awarded to employees during the establishment of office locations devoted to Mid-Continent activities during 2011.

Interest expense, net. Net interest expense increased to $21.2 million in 2012 up from $17.0 million in 2011 due to higher debt levels, slightly offset by a reduced weighted average interest rate. Debt balances averaged $228.9 million during 2012 and $173.2 million during 2011. Interest rates averaged 11.1% during 2012 and 12.5% during 2011. Amounts of interest expense capitalized to net oil and gas properties during 2012 and 2011 are discussed in “Item 8, Note 2, Significant Accounting Policies.”

Loss from equity investment. Loss from equity investment was zero for the year ended December 31, 2012 compared to a $2.0 million loss for the year ended December 31, 2011. The Company recorded an “other than temporary impairment” on its equity method investment in Attune Australia, LLC during the third quarter of 2011. The investment value was zero at December 31, 2012 and 2011.

Loss on sale or disposal of inventory. The loss on sale or disposal of inventory for 2012 increased to $1.0 million up from $20,000 in 2011. During 2012, the majority of pipe and casing inventory in storage yards was sold to an unrelated third party after it was determined that it would not be utilized in the Company’s projected 2013 drilling program. During 2011, there were no sales or lower of cost or market adjustments; only a minor disposal occurred.

Other income (expense), net. For 2012, other income was $431,000 as compared to $204,000 in 2011. The increase was mainly due to the timing of receipt of various non-recurring miscellaneous income items.

Income tax (benefit) provision. For 2012, the Company recorded an income tax benefit of $1.8 million as compared to an income tax provision of $17.3 million for 2011. Income tax (benefit) provision recognized was based on effective tax rates of 40.9% for 2012 and 40.5% for 2011. The Company’s effective tax rate differs from the statutory U.S. federal income tax rate primarily because of state and local income taxes and tax percentage depletion in excess of cost basis.

During 2012, the Company filed a refund claim with the IRS to carryback the net operating loss (“NOL”) generated in 2011 to the 2009 tax year. The NOL carryback lowered federal taxable income in 2009, and therefore also lowered the amount of the Section 199 deduction allowed for that year. The decrease in the 2009 Section 199 deduction decreased the amount of the income tax refund by $1.4 million. The tax effect of the decreased Section 199 deduction combined with the net state income tax benefit from the change in estimated 2011 taxable income caused a 20.6% decrease to the Company’s 2012 effective tax rate as compared to 2011.

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.

We have a total capital expenditure budget of $82 million for 2014, which is a 35% decrease over the $126 million invested during 2013. Our capital budget may need to be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

Capital Expenditure Budget

The 2014 capital budget consists of:

•

$19 million for geological and geophysical costs, including leasing;

•

$24 million for Louisiana state water drilling and development;

•

$10 million for onshore conventional drilling and development;

•

$10 million for California drilling and development;

•

$15 million for projects in progress; recompletions; and

•

$4 million for new ventures to be developed.

assets. Although the Company has no current plans to use the Amended Revolving Credit Facility (discussed below) to fund capital expenditures, if our cash flows from operations in the remainder of 2014 and the proceeds from sales of non-core assets are not sufficient to meet our capital expenditure requirements, the Company could use the Amended Revolving Credit Facility to fund any deficiency in order to continue the exploration and development activities.

Amended Revolving Credit Facility

The Third Amended and Restated Credit Agreement, as amended (the “Amended Revolving Credit Facility”) has a maturity date of July 1, 2015. The borrowing base is $50.0 million, of which zero and $50.0 million were drawn at December 31, 2013 and at December 31, 2012, respectively. The Credit Agreement governing the Amended Revolving Credit Facility includes covenants restricting certain of the Company’s financial ratios, including its current ratio and a debt coverage ratio, and a limitation on general and administrative expenses. The covenants also include limitations on borrowings, investments, and distributions. The Company was in compliance with these debt covenants at December 31, 2013.

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

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

12.50% Senior Secured Notes due 2015

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

On July 15, 2011, we 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 we 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, we closed an exchange offer registering all of the Additional Notes.

On April 11, 2013, we 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 we 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. We used the net proceeds from the offering to repay existing indebtedness under our Amended Revolving Credit Facility and for general corporate purposes. On November 5, 2013, we closed an exchange offer registering all of the New Additional Notes.

As of December 31, 2013, 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 $251.0 million as of December 31, 2013.

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

Cash Flows

The table below discloses the net cash provided by (used in) operating activities, investing activities and financing activities for the years ended December 31, 2013, 2012 and 2011.


	Year Ended December 31,
	(dollars in thousands)
	2013			2012			2011
Net cash provided by operating activities	$	78,742		$	128,278		$	172,928
Net cash used in investing activities		(52,652	)		(155,007	)		(246,034	)
Net cash provided by (used in) financing activities		(3,903	)		43,657			43,817

Net increase (decrease) in cash and equivalents	$	22,187		$	16,928		$	(29,289	)

Cash Flows Provided by Operating Activities

Cash provided by operating activities was $78.7 million during 2013 as compared to cash provided by operating activities of $128.3 million during 2012. The decrease in operating cash flows during 2013 was principally attributable to the timing of receipts on accounts receivable, the timing of payments on accounts payable and higher interest due on the Senior Notes at year-end 2013 as compared to year-end 2012.

Cash provided by operating activities was $128.3 million during 2012 as compared to cash provided by operating activities of $172.9 million during 2011. The decrease in operating cash flows during 2012 was principally attributable to the timing of payments on accounts payable and a lower level of revenues payable outstanding at year-end 2012 as compared to year-end 2011.

Our operating cash flows are sensitive to a number of variables, the most significant of which is the volatility of oil and gas prices. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors significantly impact the prices of these commodities. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, please see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.”

Cash Flows Used in Investing Activities

Investing activities used cash totaling $52.7 million during 2013 as compared to cash used in investing of $155.0 million during 2012. Cash used in investing activities decreased in 2013 as compared to 2012 primarily because of a reduction in drilling projects in Louisiana state waters and onshore Texas while the Company was engaging in an active onshore leasing program and negotiating with potential joint venture partners for our Breton Sound area. During 2013, $126.3 million of capital expenditures was offset by $68.9 million of proceeds from sales of non-core assets (discussed later in this section).

Investing activities used cash totaling $155.0 million during 2012 as compared to cash used in investing of $246.0 million during 2011. Cash used in investing activities decreased in 2012 as compared to 2011 primarily because of decreased drilling in Louisiana state waters and federal waters combined with increased drilling in less expensive onshore areas including Texas and California. Onshore drilling costs are lower than Gulf of Mexico drilling costs due to dissimilarities in the complexity of the well formations in the different geographic locations. During 2012, $180.5 million of capital expenditures was offset by $26.4 million of proceeds from property sales.

Our capital expenditures for drilling, development and acquisition costs for the years ended December 31, 2013, 2012 and 2011 are summarized in the following table:


	Year Ended December 31,
	(dollars in thousands)
	2013		2012		2011
Project Area
Federal	$	12,974	$	3,193	$	5,726
Shallow State Waters		40,226		64,510		88,543
Onshore Texas, Louisiana and Mississippi		45,070		84,684		91,274
Oklahoma, California and Mid-Continent		28,050		28,113		42,635

Total	$	126,320	$	180,500	$	228,178

Cash Flows Provided by (Used in) Financing Activities

Cash used in financing activities was $3.9 million during 2013 as compared to cash provided by financing activities of $43.7 million during 2012. Cash flows used in financing during 2013 consisted primarily of a $51.5 million (including a premium of $1.5 million) issuance of additional 2015 Senior Secured Notes and $6.8 million in borrowings for our insurance premium financing offset by payments of $56.2 million on our revolving credit facility and other borrowings, $2.8 million for the purchase of treasury stock and $1.6 million for shareholder dividends. Cash flows provided by financing during 2012 related primarily to $50.0 million proceeds from our credit facility offset by $6.3 million for shareholder dividends.

Cash provided by financing activities was $43.7 million during 2012 as compared to cash provided by financing activities of $43.8 million during 2011. Cash flows provided by financing during 2012 related primarily to $50.0 million proceeds from our credit facility offset by $6.3 million for shareholder dividends. Cash flows provided by financing during 2011 related primarily to a $51.3 million (including a premium of $1.3 million) issuance of additional 2015 Senior Secured Notes and $8.0 million in borrowings for our insurance premium financing offset by $7.3 million of payments on borrowings and $6.1 million for shareholder dividends.

Oil and Gas Derivatives

As part of our risk management program, we utilize derivative transactions to reduce the variability in cash flows associated with a portion of our anticipated oil and gas production to reduce our exposure to fluctuations in oil and natural gas prices. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and more price sensitive drilling programs. Our decision on the quantity and price at which

we choose to hedge our future production is based in part on our view of current and future market conditions. We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.”

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

At December 31, 2013, commodity derivative instruments were in place covering approximately 49% of our projected oil and natural gas sales for 2014 and 33% of our projected oil and natural gas sales for 2015.

As of December 31, 2013, we had entered into the following oil derivative instruments:


	NYMEX Contract Price
	Total Swaps
Period	Volume in Bbls/Mo		Weighted Average Fixed Price
2014		34,081	$	88.75


	NYMEX Contract Price
	Sell Put				Buy Put
Period	Volume in Bbls/Mo		Weighted Average Fixed Price		Volume in Bbls/Mo		Strike Price
2014 (1)		15,925	$	63.60		—		—
2015		20,945	$	70.00		20,945	$	90.00

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

As of December 31, 2013, we had entered into the following natural gas derivative instruments:


	Total Swaps
Period	Volume in MBtu/Mo		Weighted Average Fixed Price
2014		514,877	$	3.95
2015		252,475	$	4.74

Please see Item 8, “Notes to Consolidated Financial Statements–Note 6, Commodity Derivative Instruments and Derivative Activities” included elsewhere in this annual report for additional discussion regarding the accounting applicable to our derivative program.

Contractual Obligations

We have various contractual obligations in the normal course of our operations and financing activities. The following schedule summarizes our contractual obligations and other contractual commitments as of December 31, 2013 in thousands:


	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
12.50% Notes Due 2015(1)		304,688		31,250		273,438		—		—
Promissory note(2)		3,824		325		651		651		2,197
Other indebtedness(3)		2,493		2,493		—		—		—
Operating leases(4)		1,272		586		686		—		—
Drilling rig commitments(5)		1,040		1,040		—		—		—

Total	$	313,317	$	35,694	$	274,775	$	651	$	2,197

(1)	A principal repayment of $250 million is included in the 1-3 year column. All other amounts represent interest.

(2)	Consists of a promissory note with Business Property Lending Inc. in the aggregate principal and interest amount of $3.8 million relating to the construction of our Houston, TX office building.

(3)	Consists of $2.5 million of outstanding indebtedness relating to the financing of the premiums on our annual insurance policy.

(4)	Consists of office space leases for our Lexington, KY, New Orleans, LA, Bakersfield, CA and Lakewood, CO offices.

(5)	Consists of obligations under a drilling rig contract for one rig during 2014. This contract was entered into in the normal course of business to ensure rig availability to allow us to execute our business objectives.

As of December 31, 2013, the Company has asset retirement obligations of $14.1 million recorded in current liabilities. These are expected to be settled within one year. As of December, 31, 2013, the Company has asset retirement obligations of $29.1 million recorded in long-term liabilities. The Company does not have these amounts classified by year expected to settle in the table above due to the unpredictable nature of plugging and abandonment obligations. The expected lives of these wells could change from period to period.

Off-Balance Sheet Arrangements

As of December 31, 2013, we had no off-balance sheet arrangements as defined by Item 303(a)(4)(ii) of Regulation S-K. We have no plans to enter into any off-balance sheet arrangements in the foreseeable future.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with 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. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. Please see Item 8, “Notes to Consolidated Financial Statements—Note 2, Significant Accounting Policies” for a discussion of additional accounting policies and estimates made by management.

Oil and Natural 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 $8.2 million, $4.9 million and $5.2 million for the years ended December 31, 2013, 2012 and 2011, respectively. The Company capitalized interest of $2.4 million, $6.8 million and $7.0 million during the years ended December 31, 2013, 2012 and 2011, respectively, related to significant properties not subject to amortization.

Unevaluated properties and associated costs not currently being amortized and included in oil and gas properties were $45.8 million and $81.3 million at December 31, 2013 and December 31, 2012, respectively. The Company believes that the unevaluated properties at December 31, 2013 will be substantially evaluated during 2014, 2015 and 2016, and the costs will begin to be amortized at that time.

Each quarter, we review the carrying value of our capitalized oil and gas properties under the full cost accounting guidance of the SEC. This review is referred to as a “ceiling test.” Capitalized costs, less accumulated amortization and related deferred income taxes, shall not exceed an amount equal to the sum of the estimated present value of future net cash flows from proved reserves discounted at 10%, less estimated future expenditures to be incurred in developing and producing the proved reserves based on current economic and operating conditions, plus the lower of cost or fair value of unproved properties, each after income tax effects. To calculate estimated future net revenues, current prices are calculated using the average of the first-day-of-the-month price for the trailing 12-month period. The Company recorded $336.0 million of non-cash write downs of the carrying value of its proved oil and natural gas properties during the year ended December 31, 2013, as a result of “ceiling test” limitations. The Company recorded $37.0 million of non-cash write downs of the carrying value of its proved oil and natural gas properties during the year ended December 31, 2012, as a result of “ceiling test” limitations. There were no write downs resulting from the “ceiling test” during the year ended December 31, 2011. Future evaluation of unevaluated properties, oil and gas sales prices and changes in proved reserve estimates will affect the results of future ceiling tests.

Proved Oil and Natural Gas Reserves

Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. Our engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense. Proved oil and natural gas reserves are the estimated quantities of oil and natural gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under defined economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The accuracy of a reserve estimate is a function of: (i) the quality and quantity of available data; (ii) the interpretation of that data; (iii) the accuracy of various mandated economic assumptions and (iv) the judgment of the persons preparing the estimate. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves. Please see Item 8, “Notes to Consolidated Financial Statements— Note 2, Significant Accounting Policies” included elsewhere in this annual report. Our estimated proved reserves for the year ended December 31, 2011 were prepared by Netherland, Sewell & Associates, Inc., an independent oil and natural gas reservoir engineering consulting firm, and H.J. Gruy and Associates, Inc., an independent oil and natural gas reservoir engineering consulting firm. For the year ended December 31, 2012 our estimated proved reserves were prepared by Netherland, Sewell & Associates, Inc., an independent oil and natural gas reservoir engineering consulting firm, H.J. Gruy and Associates, Inc., an independent oil and natural gas reservoir engineering consulting firm, and Cawley, Gillespie & Associates, Inc., an independent oil and natural gas reservoir engineering consulting firm. For the year ended December 31, 2013,

our estimated proved reserves were prepared by Netherland, Sewell & Associates, Inc., an independent oil and natural gas reservoir engineering consulting firm, and Cawley, Gillespie & Associates, Inc., an independent oil and natural gas reservoir engineering consulting firm.

Depreciation, Depletion and Amortization

The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease respectively.

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

Sales of Oil and Gas Properties

Pursuant to the full-cost method of accounting, sales of proved and unproved oil and gas 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 fourth quarter of 2013, the Company completed asset sales totaling $51.6 million to an unrelated third party. The Company sold approximately 62,000 net acres in oil, gas and/or mineral leases located in Texas and Colorado for $41.8 million and approximately 34,000 net acres in oil, gas and/or mineral leases located in Oklahoma for $9.8 million. The Oklahoma acreage sold included 3.6% of the Company’s total proved reserves at December 31, 2012. These amounts were recorded as reductions to net oil and gas properties with no income statement impact because the sales did not significantly alter the relationship between capitalized costs and proved reserves.

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 will also receive 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 sheets, with no income statement impact because the sale did not significantly alter the relationship between capitalized costs and proved reserves. As of December 31, 2013, the Company had received $9.8 million of the carry from the unrelated third party. Of this amount, $6.0 million of drilling costs had been incurred as of December 31, 2013, and $3.8 million was recorded in Advances from joint interest partners on the consolidated balance sheet.

During the fourth quarter of 2012, the Company sold approximately 40,000 acres in Oklahoma to a former joint venture partner. The sales price was approximately $10.0 million and was recorded as a reduction to our net oil and gas properties on the accompanying consolidated balance sheets, with no income statement impact because the sale did not significantly alter the relationship between capitalized costs and proved reserves.

During the third quarter of 2012, the Company sold approximately 15,000 net acres in oil, gas and/or mineral leases and a total of approximately 56,000 net acres, which includes options in oil, gas and/or mineral leases, located in Texas and Louisiana and a well and related equipment located in Louisiana, along with all of our contracts and agreements related to this property to an unrelated third party. The sales price was approximately $14.0 million and was recorded as a reduction to net oil and gas properties on the accompanying consolidated balance sheets, 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 2012, the Company sold a wellbore and production facility in Louisiana state waters to an unrelated third party. The sales price was approximately $2.0 million and was recorded as a reduction to our net oil and gas properties on the accompanying consolidated balance sheets, 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 2011, the Company sold approximately 16,000 acres onshore Mississippi to an unrelated third party oil and gas company. The sales price was approximately $2.2 million and was recorded in cash and as a reduction to our net oil and gas properties on the accompanying consolidated balance sheets, with no income statement impact because the sale does not significantly alter the relationship between capitalized costs and proved reserves.

Asset Retirement Obligations

In accordance with the provisions of FASB guidance related to accounting for asset retirement obligations and FASB guidance on accounting for conditional asset retirement obligations, costs associated with the retirement of fixed assets (e.g., oil and gas production facilities, etc.) that the Company is legally obligated to incur are accrued. The fair value of the obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the asset and are depreciated over the life of the applicable asset. The asset retirement cost recorded in oil and gas properties being amortized at December 31, 2013 was $37.8 million. The asset retirement liability at December 31, 2013 was $43.2 million. Accretion of the discounted asset retirement obligations is recognized as an increase in the carrying amount of the liability and as an expense within depreciation, depletion and amortization in the accompanying consolidated statement of operations. A discount rate of 5% was used to calculate the asset retirement obligation until September 24, 2010, at which time the Company began using a discount rate of 12.5%, the rate of the newly issued 2015 Senior Secured Notes. Other critical assumptions used to calculate asset retirement obligations include reserve lives as reported by our independent oil and natural gas reservoir engineering consulting firms, current market rates for plugging and abandonment activities and historical costs the Company has incurred on its plugging and abandonment activities.

Derivative Activities

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

The Company recognizes its derivative instruments on the 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 hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and records the unrealized changes in fair value in Realized and unrealized gains(losses) on derivatives, net in the accompanying consolidated statements of operations. All realized cash settlements of derivative activities are also recorded in Realized and unrealized gains (losses) on derivatives, net in the accompanying consolidated statements of operations. See Item 8, “Notes to Consolidated Financial Statements—Note 6, Commodity Derivative Instruments and Derivative Activities” included elsewhere in this annual report for further details.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2013, 2012 or 2011. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

Our primary market risk exposure is in the pricing applicable to our crude oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our United States natural gas production. Pricing for crude oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control including volatility in the differences between product prices at sales points and the applicable index price. Hypothetical changes in commodity prices chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations. However, since it is not possible to accurately predict future changes in commodity prices, this hypothetical change may not necessarily be an indicator of probable future fluctuations. Based on our average daily production for the year ended December 31, 2013, our oil sales would increase or decrease by approximately $8.8 million for each $10.00 per barrel change in crude oil prices and our gas sales would increase or decrease by approximately $14.9 million for each $1.00 per MMBtu change in natural gas prices, excluding the effects of existing commodity derivatives.

To partially reduce price risk caused by these market fluctuations, we utilize derivative transactions to reduce the variability in cash flows associated with a portion of our anticipated crude oil and natural gas production as part of our risk management program. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and more price sensitive drilling programs. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. While hedging limits the downside risk of adverse price movements, it also may limit future revenues from favorable price movements. The use of derivative transactions also involves the risk that counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty.

At December 31, 2013, $(2.9) million represented the fair value of the commodity derivatives. This $(2.9) million was made up of approximately $1.6 million in assets, which were recorded in long term assets and $(4.5) million in liabilities recorded in current and long-term liabilities. At December 31, 2012, $1.5 million represented the fair value of the commodity derivatives. This $1.5 million was made up of approximately $3.7 million in assets, which were recorded in both current and long term assets and approximately $(2.2) million in liabilities recorded in long-term liabilities. A 10% increase in prices used at December 31, 2013 would have reduced the asset fair value by $7.3 million and a 10% decrease in prices would have increased the asset fair value by $7.5 million.

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


			Volume in		NYMEX
	Contract		MMBtus/		Strike
Remaining Contract Term	Type		Month		Price
January 2014 - June 2014		Swap		150,833	$	4.09
January 2014 - December 2014		Swap		152,083	$	3.67
January 2014 - December 2014		Swap		121,083	$	4.15
January 2014 - December 2014		Swap		79,850	$	4.00
January 2014 - December 2014		Swap		71,111	$	3.98
July 2014 - December 2014		Swap		30,667	$	4.00
January 2015 - December 2015		Swap		167,042	$	4.94
January 2015 - December 2015		Swap		85,433	$	4.35

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


		Volume in		NYMEX
	Contract	BBls/		Strike
Remaining Contract Term	Type	Month		Price
January 2014 - June 2014	Swap		24,133	$	85.40
January 2014 - December 2014	Swap		16,648	$	92.10
January 2014 - September 2014	Put - Sell		21,233	$	63.60
July 2014 - September 2014	Swap		21,467	$	85.90
January 2015 - December 2015	Put - Buy		20,945	$	90.00
January 2015 - December 2015	Put - Sell		20,945	$	70.00

For a further discussion of our derivative activities, please see Item 8, “Notes to Consolidated Financial Statements — Note 3, Fair Value Measurements” and “Note 6, Commodity Derivative Instruments and Derivative Activities” included elsewhere in this annual 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 ($5.5 million at December 31, 2013) and the sale of our crude oil and natural gas production, which we market to energy marketing companies and transmission companies ($19.5 million in receivables at December 31, 2013). 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. The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of those contracts. See Item 8, “Notes to Consolidated Financial Statements —Note 6, Commodity Derivative Instruments and Derivative Activities” included elsewhere in this annual report.

Interest Rate Risk

Our exposure to changes in interest rates relates primarily to long-term debt obligations. Historically, we were exposed to changes in interest rates as a result of our revolving credit facility and this exposure will remain under our Amended Revolving Credit Facility. We had zero and $50 million outstanding under the Amended Revolving Credit Facility at December 31, 2013 and 2012, respectively. We do not believe our interest rate exposure warrants entry into interest rate hedges and have, therefore, not hedged our interest rate exposure.

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of RAAM Global Energy Company

We have audited the accompanying consolidated balance sheets of RAAM Global Energy Company as of December 31, 2013 and 2012, and the related consolidated statements of operations, equity and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of RAAM Global Energy Company at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Louisville, Kentucky

March 31, 2014

RAAM GLOBAL ENERGY COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except for share amounts)


	December 31,			December 31,
	2013			2012
Assets
Current assets:
Cash and cash equivalents	$	90,858		$	68,671
Accounts receivable, net of $656 and $185 allowance for doubtful accounts in 2013 and 2012, respectively		5,472			4,598
Revenues receivable		19,517			28,527
Income taxes receivable		507			1,438
Deferred tax asset - current		3,938			872
Commodity derivatives – current portion		—			2,369
Prepaid assets		3,863			3,180
Other current assets		4,596			4,063

Total current assets		128,751			113,718
Oil and gas properties (full-cost method):
Properties being amortized		1,432,310			1,340,650
Properties not subject to amortization		45,752			81,292
Less accumulated depreciation, depletion, and amortization		(1,190,944	)		(767,674	)

Net oil and gas properties		287,118			654,268
Other assets:
Other capitalized assets, net		7,252			6,771
Commodity derivatives		1,541			1,381
Other		1,950			3,316

Total other assets		10,743			11,468

Total assets	$	426,612		$	779,454

See accompanying notes to consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except for share amounts)


	December 31,			December 31,
	2013			2012
Liabilities and equity
Current liabilities:
Accounts payable and accrued liabilities	$	28,066		$	19,627
Revenues payable		17,699			24,587
Interest payable - senior secured notes		7,813			6,250
Current taxes payable		25			313
Advances from joint interest partners		4,852			85
Commodity derivatives - current portion		4,467			1,114
Asset retirement obligations - current portion		14,089			11,195
Debt – current portion		2,626			1,975

Total current liabilities		79,637			65,146
Other liabilities:
Commodity derivatives		10			1,091
Asset retirement obligations		29,138			28,178
Debt		2,448			52,584
Senior secured notes		251,037			199,982
Deferred income taxes		14,178			138,596
Other long-term liabilities		149			328

Total other liabilities		296,960			420,759
Total liabilities		376,597			485,905
Commitments and contingencies (see Note 14)
Equity:
Common stock, $0.01 par value, 380,000 shares authorized, 61,425 and 62,500 outstanding in 2013 and 2012, respectively		63,521			62,478
Treasury stock at cost, 6,873 and 5,166 shares in 2013 and 2012, respectively		(8,552	)		(5,736	)
Retained earnings (accumulated deficit)		(7,441	)		235,538

Total equity attributable to RAAM Global		47,528			292,280
Noncontrolling interest		2,487			1,269

Total equity		50,015			293,549

Total liabilities and equity	$	426,612		$	779,454

See accompanying notes to consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands)


	2013			2012			2011
Revenues:
Gas sales	$	62,953		$	63,535		$	87,064
Oil sales		91,618			119,504			113,722
Realized and unrealized gains (losses) on derivatives, net		(5,038	)		20,769			13,650

Total revenues		149,533			203,808			214,436
Operating expenses:
Production and delivery costs		35,003			35,529			34,326
Production taxes		7,965			9,314			10,259
Workover costs		3,729			2,772			7,730
Depreciation, depletion and amortization		426,061			118,041			71,763
General and administrative expenses		21,359			20,780			28,861

Total operating expense		494,117			186,436			152,939

Income (loss) from operations		(344,584	)		17,372			61,497
Other income (expenses):
Interest expense, net		(29,569	)		(21,237	)		(16,954	)
Loss from equity investment		—			—			(2,044	)
Loss on sale or disposal of inventory		—			(954	)		(20	)
Other income (expense), net		(126	)		431			204

Total other income (expenses):		(29,695	)		(21,760	)		(18,814	)

Income (loss) before taxes		(374,279	)		(4,388	)		42,683
Income tax provision (benefit)		(134,080	)		(1,796	)		17,295

Net income (loss) including noncontrolling interest		(240,199	)		(2,592	)		25,388

Net income attributable to noncontrolling interest (net of tax)		1,218			1,314			1,524

Net income (loss) attributable to RAAM Global	$	(241,417	)	$	(3,906	)	$	23,864

See accompanying notes to consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

CONSOLIDATED STATEMENTS OF

EQUITY

(In thousands, except share data)


											Retained
	Common Stock					Treasury Stock					Earnings (Accumulated			Noncontrolling
	Shares			Amount		Shares		Amount			Deficit)			Interest			Total
Balance, January 1, 2011		60,000		$	56,096		5,166	$	(5,736	)	$	244,841		$	—		$	295,201
Issuance of common stock		2,500			6,333													6,333
Purchase of noncontrolling interest					49													49
Change in noncontrolling interest												(16,948	)		(1,569	)		(18,517	)
Payment of dividends												(6,063	)					(6,063	)
Net income												23,864			1,524			25,388

Balance, December 31, 2011		62,500		$	62,478		5,166	$	(5,736	)	$	245,694		$	(45	)	$	302,391
Payment of dividends												(6,250	)					(6,250	)
Net income (loss)												(3,906	)		1,314			(2,592	)

Balance, December 31, 2012		62,500		$	62,478		5,166	$	(5,736	)	$	235,538		$	1,269		$	293,549
Issuance of common stock		632			1,043													1,043
Purchase of treasury stock		(1,707	)				1,707		(2,816	)								(2,816	)
Payment of dividends												(1,562	)					(1,562	)
Net income (loss)												(241,417	)		1,218			(240,199	)

Balance, December 31, 2013		61,425		$	63,521		6,873	$	(8,552	)	$	(7,441	)	$	2,487		$	50,015

See accompanying notes to consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	2013			2012			2011
Operating activities
Net income (loss) including noncontrolling interest	$	(240,199	)	$	(2,592	)	$	25,388
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		427,906			119,868			73,957
Deferred income taxes		(127,484	)		21,652			14,274
Stock-based compensation expense		1,043			—			6,333
Loss on sale or disposal of inventory		—			954			20
Impairment of equity method investment		—			—			2,044
Changes in assets and liabilities:
Accounts and revenues receivable		7,630			4,049			6,941
Income tax receivables		931			680			837
Other current assets		(600	)		666			(815	)
Change in derivatives, net		4,480			10,076			(4,815	)
Accounts payable and accrued liabilities		10,826			(22,118	)		36,137
Current taxes payable		(287	)		(86	)		(526	)
Interest payable on Senior Notes		1,563			—			1,202
Revenues payable		(6,888	)		(4,732	)		11,484
Other long-term liabilities		(179	)		(139	)		467

Net cash provided by operating activities		78,742			128,278			172,928
Investing activities
Change in advances from joint interest partners		4,767			(934	)		1,019
Payment of prepaid drilling expenses		—			—			(555	)
Additions to oil and gas properties and equipment		(126,320	)		(180,500	)		(227,623	)
Purchase of noncontrolling interest		—			—			(21,000	)
Proceeds from net sales of oil and gas properties		68,901			26,427			2,125

Net cash used in investing activities		(52,652	)		(155,007	)		(246,034	)
Financing activities
Proceeds from revolving credit facility		—			50,000			—
Proceeds from borrowings		6,757			7,101			8,037
Payments on debt		(56,242	)		(7,204	)		(7,347	)
Deferred loan costs		—			—			(469	)
Proceeds from issuance of 12.5% Senior Notes due 2015		51,500			—			51,250
Deferred bond costs		(1,540	)		—			(1,510	)
Purchase of treasury stock		(2,816	)		—			—
Payment of dividends		(1,562	)		(6,250	)		(6,063	)
Other		—			10			(81	)

Net cash provided by (used in) financing activities		(3,903	)		43,657			43,817

Increase (decrease) in cash and cash equivalents		22,187			16,928			(29,289	)
Cash and cash equivalents, beginning of period		68,671			51,743			81,032

Cash and cash equivalents, end of period	$	90,858		$	68,671		$	51,743

See accompanying notes to consolidated financial statements.

RAAM GLOBAL ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Nature of Business

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

2. Significant Accounting Policies

Basis of Accounting and Principles of Consolidation

The accompanying consolidated financial statements are presented on the accrual basis of accounting in accordance with U.S. generally accepted accounting principles. The accompanying consolidated financial statements of RAAM Global include the accounts of RAAM Global, its wholly-owned subsidiaries, and variable interest entities where RAAM Global is the primary beneficiary. Intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles 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.

Financial Instruments

The Company considers all highly liquid financial instruments with an original maturity of three months or less to be cash equivalents.

The Company includes fair value information in the notes to financial statements when the fair value of its financial instruments is different from the book value.

Oil and Gas Properties

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.

Each quarter, we review the carrying value of our capitalized oil and gas properties under the full cost accounting guidance of the SEC. This review is referred to as a “ceiling test.” Capitalized costs, less accumulated amortization and related deferred income taxes, shall not exceed an amount equal to the sum of the estimated present value of future net cash flows from proved reserves discounted at 10%, less estimated future expenditures to be incurred in developing and producing the proved reserves based on current economic and operating conditions, plus the lower of cost or fair value of unproved properties, each after income tax effects. To calculate estimated future net revenues, current prices are calculated using the average of the first-day-of-the-month price for the trailing 12-month period. These prices are used except where different prices are fixed and determinable through contractual arrangements. Details specific to the Company’s ceiling tests for the periods presented in the accompanying consolidated financial statements are discussed in Note 5, Property, Plant and Equipment and Asset Retirement Obligations.

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.

There are certain related party entities that are joint interest and revenue partners in certain of the Company’s properties. See Note 13, Related-party Transactions, for further information.

Other Capitalized Assets

Buildings and improvements, office equipment, software, furniture, fixtures, and leased equipment are depreciated over their estimated useful lives (2 - 32 years) using the straight-line method. See Note 5, Property, Plant and Equipment and Asset Retirement Obligations, for additional information.

Derivative Activities

The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on anticipated settlement dates. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and records the unrealized changes in fair value in Realized and unrealized gains (losses) on derivatives, net in the accompanying consolidated statements of operations. All realized cash settlements of derivative activities are also recorded in Realized and unrealized gains (losses) on derivatives, net in the accompanying consolidated statements of operations. See Note 6, Commodity Derivative Instruments and Derivative Activities for further details.

Income Taxes

The Company follows Financial Accounting Standards Board (“FASB”) guidance on accounting for income taxes. The asset and liability method prescribed by this guidance requires recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the tax bases and financial reporting bases of assets and liabilities. Interest and penalties on tax payments are recorded as a component of the income tax provision.

Revenue Recognition and Taxes Paid to Governmental Authorities

The Company recognizes natural gas and oil sales from its interests in producing wells under the sales method of accounting. Under the sales method, the Company recognizes revenues based on the amount of natural gas or oil sold to purchasers, which may differ from the amounts to which the Company is entitled, based on its interest in the properties. Gas balancing obligations as of December 31, 2013, 2012 and 2011 were not significant. Severance taxes incurred to governments were $8.0 million, $9.3 million and $10.3 million for 2013, 2012 and 2011, respectively, and were recorded in Production taxes in the accompanying consolidated statements of operations.

Accounting for Accounts and Revenues Receivable

The Company records receivables due within one year at the outstanding value, adjusted for the allowance for doubtful accounts. Accounts receivable is made up of joint interest billings (“JIB”) to partners for well expenses incurred prior to year-end that remain unpaid at the balance sheet date. Revenues receivable is made up of amounts due from purchasers for oil and gas volumes sold prior to year-end that remain unpaid at the balance sheet date. The Company uses the aging of receivables to calculate the allowance for doubtful accounts.

Accounting for Asset Retirement Obligations

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 as follows:

•

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 December 31, 2013 and 2012, 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 (Level 2) and are valued by reference to similar financial instruments, adjusted for credit risk and restrictions and other terms specific to the contracts.

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


	Fair Value Measurements Using
*In Thousands*	Quoted Price in Active Markets (Level 1)		Significant Other Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Fair Value			Netting⁽¹⁾			Carrying Amount
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	)
December 31, 2012
Assets:
Commodity derivatives	$	—	$	8,429		$	—	$	8,429		$	(4,679	)	$	3,750
Liabilities:
Commodity derivatives		—		(6,884	)		—		(6,884	)		4,679			(2,205	)

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

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


	Fair Value Measurements Using Significant Other Observable Inputs (Level 2)
Description	December 31, 2013			December 31, 2012
*In thousands*
Assets:
Fair value of commodity derivatives - current assets	$	—		$	2,369
Fair value of commodity derivatives - long-term assets		1,541			1,381

Total Assets	$	1,541		$	3,750

Liabilities:
Fair value of commodity derivatives - current liabilities	$	(4,467	)	$	(1,114	)
Fair value of commodity derivatives - long-term liabilities		(10	)		(1,091	)

Total Liabilities	$	(4,477	)	$	(2,205	)

2015 Senior Secured Notes

During September 2010, July 2011 and April 2013, the Company issued Senior Secured Notes. At December 31, 2013, the fair value of the Notes was estimated to be $259.1 million, based on the prices the bonds have recently been quoted at in the market, which represent Level 2 inputs. As of December 31, 2013, a total of $250.0 million notional amount of the Notes was outstanding. The carrying amount of the Notes was $251.0 million as of December 31, 2013.

At December 31, 2012, the fair value of the Notes was estimated to be $206.0 million, based on the prices the bonds have recently been quoted at in the market, which represent Level 2 inputs. As of December 31, 2012, a total of $200.0 million notional amount of the Notes was outstanding. The carrying amount of the Notes was $200.0 million as of December 31, 2012.

Amended Revolving Credit Facility

The borrowing base for the Amended Revolving Credit Facility is $50.0 million of which zero was drawn at December 31, 2013 and $50 million was drawn at December 31, 2012. The carrying amount of the revolving credit facility approximates the fair value due to the variable interest rate on this debt.

The book values of those financial instruments that are classified as current assets or liabilities approximate fair value because of the short maturity of those instruments.

4. Accounts and Revenues Receivable

Accounts and revenues receivable at December 31, 2013 and 2012 were $25.0 million and $33.1 million, respectively, all of which were due from companies in the oil and gas industry. Of the revenues receivable, $16.5 million was due from five companies and $24.0 million was due from five companies at December 31, 2013 and December 31, 2012, respectively.

Since all of the Company’s accounts receivable from purchasers and joint interest owners at December 31, 2013 and December 31, 2012 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 December 31, 2013 and December 31, 2012. Management obtains letters of credit from its major purchasers and continually evaluates the creditworthiness of its partners.

The Company sold natural gas and oil production representing 10% or more of its natural gas and oil revenues for the years ended December 31, 2013, 2012 and 2011 to the following customers as listed below. In the exploration, development, and production business, production is normally sold to relatively few customers. However, based on the current demand for natural gas and oil, management believes that the loss of any major customers would not have a material adverse effect on operations. The Company believes that it could replace any one of the major customers if necessary without a major disruption in sales.


	2013			2012			2011
Company A		32	%		35	%		12	%
Company B		21	%		17	%		15	%
Company C		16	%		14	%		15	%
Company D		11	%		(a	)		(a	)
Company E		(a	)		10	%		(a	)
Company F		(a	)		(a	)		27	%

(a)	Revenues from this customer were less than 10% in this year.

5. Property, Plant and Equipment and Asset Retirement Obligations

Property, plant and equipment consisted of the following at December 31, 2013 and 2012:


	December 31,
	2013			2012
Oil and natural gas properties (full cost method):
Properties being amortized	$	1,432,310		$	1,340,650
Properties not subject to amortization		45,752			81,292

Total oil and natural gas properties		1,478,062			1,421,942
Less accumulated depreciation, depletion and amortization		(1,190,944	)		(767,674	)

Net oil and gas properties		287,118			654,268

Land		1,025			1,025
Buildings and improvements		6,492			6,406
Office equipment and software		6,246			4,862
Leased equipment		345			345
Furniture and fixtures		830			731

Total		14,938			13,369
Less accumulated depreciation		(7,686	)		(6,598	)

Net capitalized costs		7,252			6,771

Capitalized assets, net	$	294,370		$	661,039

The Company utilizes useful lives of 31.5 years for buildings and improvements, 3 to 5 years for office equipment and software, 2 to 5 years for leased equipment and 7 years for furniture and fixtures when calculating depreciation.

Oil and Gas Properties

The Company’s ceiling test computation for the fourth quarter of 2013 resulted in a $59.1 million write-down and was based on twelve-month average prices of $93.42 per barrel of oil, plus adjustments by lease for quality, transportation fees, and regional price differentials and $3.67 per MMBtu of natural gas, plus adjustments by lease for energy content, transportation fees, and regional price differentials. The Company’s ceiling test computation for the third quarter of 2013 resulted in a $276.9 million write-down and was primarily a result of the downward revisions to eliminate the Ewing Banks 920 (“EB 920” or “Flatt’s Guitar”) Project proved undeveloped reserves. During September 2013, the Company determined that it could not meet the financial certifications required to obtain permits to develop its offshore EB 920 Project in the Gulf of Mexico, due in large part to the substantially increased Worst Case Discharge (“WCD”) assumptions imposed by the Bureau of Ocean Energy Management (“BOEM”). As a result, the proved undeveloped reserves associated with the EB 920 Project no longer met the requirements of reasonable certainty to remain booked as proved reserves at the end of the third quarter of 2013. These write-downs were recorded in Depreciation, depletion and amortization in the consolidated statement of operations. For the year ended December 31, 2012, the Company’s ceiling test computation resulted in a write-down of $37.0 million and was based on twelve-month average prices of $91.21 per barrel of oil, plus adjustments, and $2.76 per MMBtu of natural gas, plus adjustments. The write-down of $37.0 million was recorded in Depreciation, depletion and amortization in the consolidated statement of operations. For the year ended December 31, 2011, the Company’s ceiling test computation did not result in a write-down and was based on twelve-month average prices of $92.71 per barrel of oil, plus adjustments, and $4.12 per MMBtu of natural gas, plus adjustments.

Sale of Oil and Gas Properties

During the fourth quarter of 2013, the Company completed asset sales totaling $51.6 million to an unrelated third party. The Company sold approximately 62,000 net acres in oil, gas and/or mineral leases located in Texas and Colorado for $41.8 million. The Company also sold approximately 34,000 net acres in oil, gas and/or mineral leases located in Oklahoma for $9.8 million. The Oklahoma acreage sold included 3.6% of the Company’s total proved reserves at December 31, 2012. These amounts were recorded as reductions to net oil and gas properties with no impact on the statement of operations because the sales did not significantly alter the relationship between capitalized costs and proved reserves.

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 will also receive 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 consolidated balance sheets, with no impact on the statement of operations because the sale did not significantly alter the relationship between capitalized costs and proved reserves. As of December 31, 2013, the Company had received $9.8 million of the carry from the unrelated third party. Of this amount, $6.0 million of drilling costs had been incurred as of December 31, 2013, and $3.8 million was recorded in Advances from joint interest partners on the consolidated balance sheet.

During the fourth quarter of 2012, the Company sold approximately 40,000 acres in Oklahoma to a former joint venture partner. The sales price was approximately $10.0 million and was recorded as a reduction to our net oil and gas properties on the accompanying consolidated balance sheets, with no impact on the statement of operations because the sale does not significantly alter the relationship between capitalized costs and proved reserves.

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

During the second quarter of 2011, the Company sold approximately 16,000 acres onshore Mississippi to an unrelated third party oil and gas company. The sales price was approximately $2.2 million and was recorded as a reduction to our net oil and gas properties on the accompanying consolidated balance sheets, with no impact on the statement of operations because the sale does not significantly alter the relationship between capitalized costs and proved reserves.

Asset Retirement Obligations

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


*In thousands*
Balance of ARO as of January 1, 2012	$	26,788
Accretion expense		1,362
Additions		2,301
Settlement of ARO		(827	)
Changes in ARO estimate		9,749

Balance of ARO as of December 31, 2012		39,373
Accretion expense		1,467
Additions		4,222
Settlement of ARO		(4,489	)
Settlement of ARO through sale of properties		(117	)
Changes in ARO estimate		2,771

Balance of ARO as of December 31, 2013	$	43,227

The change in estimate during 2013 is primarily the result of reductions in reserve lives of certain offshore federal wells that have higher AROs than onshore properties, resulting in an acceleration of recording their AROs since the estimated timeframe expected to pass until the Company is required to plug and abandon the wells is shorter than was estimated at the previous yearend.

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

The change in estimate during 2011 was primarily due to an increase in the Company’s share of plugging and abandonment obligations on one field in the Gulf of Mexico due to the Company now being responsible for a higher percentage of the plugging and abandonment on certain wells that the former owner used to share in.

6. Commodity Derivative Instruments and Derivative Activities

In order to manage the variability in cash flows associated with the sale of its oil and gas production, the Company has developed a strategy to combine the use of floors, costless collars and futures transactions in order to minimize the downside risk from adverse price movements but allow for the realization of upside profits, if available. The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of those contracts. At December 31, 2013, Shell Energy North America (US), L.P., Union Bank of California N.A., BNP PARIBAS, NATIXIS and Regions Bank are the counterparties being used by the Company.

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 NYMEX. The estimated fair value of these transactions is based on various factors that include closing exchange prices on the NYMEX, over-the-counter quotations, volatility and the time value of options. The calculation of the fair value of collars and floors utilizes the Black-Scholes option-pricing model. Since these transactions were not designated as cash flow hedges for accounting purposes, the Company marks its derivative instruments to fair value and records the unrealized changes in fair value in Realized and unrealized gains (losses) on derivatives, net in the accompanying consolidated statements of operations. All realized cash settlements of derivative activities are also recorded in Realized and unrealized gains (losses) on derivatives, net in the accompanying consolidated statements of operations.

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


			Volume in		NYMEX
	Contract		MMBtus/		Strike
Remaining Contract Term	Type		Month		Price
January 2014 - June 2014		Swap		150,833	$	4.09
January 2014 - December 2014		Swap		152,083	$	3.67
January 2014 - December 2014		Swap		121,083	$	4.15
January 2014 - December 2014		Swap		79,850	$	4.00
January 2014 - December 2014		Swap		71,111	$	3.98
July 2014 - December 2014		Swap		30,667	$	4.00
January 2015 - December 2015		Swap		167,042	$	4.94
January 2015 - December 2015		Swap		85,433	$	4.35

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


		Volume in		NYMEX
	Contract	BBls/		Strike
Remaining Contract Term	Type	Month		Price
January 2014 - June 2014	Swap		24,133	$	85.40
January 2014 - December 2014	Swap		16,648	$	92.10
January 2014 - September 2014	Put - Sell		21,233	$	63.60
July 2014 - September 2014	Swap		21,467	$	85.90
January 2015 - December 2015	Put - Buy		20,945	$	90.00
January 2015 - December 2015	Put - Sell		20,945	$	70.00

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

7. Equity Method Investments

Attune Australia

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

The Company evaluates its equity method investments on a quarterly basis to ensure proper accounting treatment is being applied. During the Company’s equity method investment review in the third quarter of 2011, new information regarding this investment was identified indicating that the joint venture which had been operating this oil field was no longer in a stable financial position and it appears unlikely that there will be production from this oil field in the foreseeable future. Given that there is no expected revenue stream from this investment, the Company believes that the investment has incurred an additional other than temporary impairment (“OTTI”) and should be written down to zero. The result of this analysis was a $2.0 million OTTI charge, which was recorded in the accompanying consolidated statements of operations in Loss from equity investments.

8. Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consisted of the following at December 31, 2013 and 2012:


	December 31,
	2013		2012
Accounts payable	$	20,447	$	14,502
Oil and gas property costs accrual		2,691		2,460
Production and delivery costs accrual		2,233		1,288
Compensation and benefits accrual		2,408		1,009
Other		287		368

Total Accounts payable and Accrued liabilities	$	28,066	$	19,627

9. Debt

2015 Senior Secured Notes

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

On July 15, 2011, the Company completed the issuance and sale of $50.0 million aggregate principal amount of additional 12.5% Senior Notes due 2015 (the “Additional Notes,” collectively with the Original Notes, the “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 offering expenses. The Company used the net proceeds from the offering to repay existing indebtedness under the Company’s amended revolving credit facility and for general corporate purposes. On November 5, 2013, the Company closed an exchange offer registering all of the New Additional Notes.

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

The senior notes contain typical restrictions on liens, mergers and sales of assets. Until October 1, 2014, the Company may redeem up to 35% of the aggregate principal amount of the 2015 Senior Secured Notes at a price equal to 112.50% of the principal amount, plus accrued and unpaid interest to the date of redemption, with the net cash proceeds of certain equity offerings. On or after October 1, 2014 until March 31, 2015, the Company may redeem some or all of the 2015 Senior Secured Notes at an initial redemption price equal to par value plus one-half the coupon plus accrued and unpaid interest to the date of redemption. On or after April 1, 2015, the Company may redeem some or all of the 2015 Senior Secured Notes at a redemption price equal to par plus accrued and unpaid interest to the date of redemption. The Company may also redeem some or all of the 2015 Senior Secured Notes at any time prior to October 1, 2014 at the “make-whole” prices and at any time on or after April 1, 2015 at par. The Company was in compliance with all debt covenants related to the Notes at December 31, 2013.

Amended Revolving Credit Facility

The Company’s Fourth Amended and Restated Credit Agreement, as amended (the “Amended Revolving Credit Facility”) has a maturity date of July 1, 2015. The borrowing base is $50.0 million of which zero was drawn at December 31, 2013 and $50.0 million was drawn at December 31, 2012. The Credit Agreement governing the Amended Revolving Credit Facility includes covenants restricting certain of the Company’s financial ratios, including its current ratio and a debt coverage ratio, and a limitation on general and administrative expenses. The covenants also include limitations on borrowings, investments, and distributions. The Company was in compliance with these debt covenants at December 31, 2013. The interest rate for borrowings under the Revolving Credit Facility is LIBOR plus 1%. The Company also incurs a 0.5% per annum commitment fee charged on the unused portion of the Revolving Credit Facility.

Promissory Note

The Company has a promissory note with GE Commercial Finance Business Property Corporation (“GECF”) related to the construction of the Houston office building. The balance was $2.6 million at December 31, 2013 and $2.7 million at December 31, 2012. The GECF note requires monthly installments of principal and interest in the amount of approximately $27,000 until September 1, 2025. There are no covenant requirements under this note. The effective interest rate on this note was 7.05% at December 31, 2013 and 2012.

Finance Agreement

During May 2013, the Company entered into an agreement to finance the premiums for its annual insurance policies. At December 31, 2013, $2.5 million was outstanding under this agreement. The finance agreement requires monthly installments of principal and interest in the amount of approximately $0.6 million until April 1, 2014. There are no covenant requirements under this agreement. The effective interest rate on this agreement was 2.95% at December 31, 2013. During 2012, the Company had a similar arrangement to finance the premiums for its annual insurance policies. The effective interest rate on this agreement was 2.5% at December 31, 2012.

Long-term Debt Maturities

The future estimated maturities of long-term debt are as follows (in thousands):


Year ending December 31:
2014	$	2,626
2015		250,158
2016		169
2017		182
2018		195
Thereafter		1,744

Total	$	255,074

Cash payments for interest totaled $28.8 million, $26.2 million, and $16.1 million for the years ended December 31, 2013, 2012, and 2011, respectively.

10. Income Taxes

Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2013 and 2012 are as follows:


	December 31,
*(In Thousands)*	2013			2012
Deferred tax assets:
Asset retirement obligation	$	15,479		$	14,156
Equity investment in unconsolidated subsidiary		—			2,690
Net operating loss carryforward		6,606			7,351
Valuation allowance⁽¹⁾		(4,081	)		—
Percentage depletion carryforward		1,733			238
AMT credit carryforward		4,641			—
Other⁽²⁾		833			223

Total deferred tax assets	$	25,211		$	24,658

Deferred tax liabilities:
Property, plant, and equipment	$	(34,266	)	$	(157,921	)
Commodity derivatives		(887	)		(4,461	)
Other		(298	)		—

Total deferred tax liabilities	$	(35,451	)	$	(162,382	)

⁽¹⁾	The valuation allowance primarily relates to the uncertainty surrounding our ability to realize recorded tax benefits on certain net operating loss carryforwards.


	December 31,
	2013			2012
Current assets	$	3,938		$	872
Long term liabilities		(14,178	)		(138,596	)

	$	(10,240	)	$	(137,724	)

The principal components of income tax provision (benefit) for the years ended December 31 are as follows:


*(In Thousands)*	2013			2012			2011
Current income tax expense (benefit):
Federal	$	(6,681	)	$	(21,697	)	$	560
State and local		84			(1,751	)		2,461

	$	(6,597	)	$	(23,448	)	$	3,021

Deferred income tax expense (benefit):
Federal	$	(117,577	)	$	20,049		$	9,737
State and local		(9,906	)		1,603			4,537

	$	(127,483	)	$	21,652		$	14,274

Total income tax provision	$	(134,080	)	$	(1,796	)	$	17,295

We received net income tax refunds of $7.6 million in 2013 compared to net income tax refunds of $23.8 million in 2012 and net income tax payments of $2.8 million made in 2011.

The Company’s 2013, 2012 and 2011 effective tax rates are 35.8%, 40.9% and 40.5%, respectively, and are comprised of the following:

2013

2012

2011

Large accelerated filer

Accelerated filer

Non-accelerated filer

x (Do not check if a smaller reporting company)

Smaller reporting company

RAAM Global Energy Co 10-K